PLAINS ALL AMERICAN PIPELINE LP - Quarter Report: 2014 March (Form 10-Q)

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 March 31, 2014

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: (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 website, 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. (Check one):

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 April 30, 2014, there were 363,873,690 Common Units outstanding.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

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	Page
PART I. FINANCIAL INFORMATION
Item 1. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
Condensed Consolidated Balance Sheets: As of March 31, 2014 and December 31, 2013	3
Condensed Consolidated Statements of Operations: For the three months ended March 31, 2014 and 2013	4
Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2014 and 2013	5
Condensed Consolidated Statement of Changes in Accumulated Other Comprehensive Income: For the three months ended March 31, 2014	5
Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2014 and 2013	6
Condensed Consolidated Statement of Changes in Partners’ Capital: For the three months ended March 31, 2014 and 2013	7
Notes to Condensed Consolidated Financial Statements:
1. Organization and Basis of Presentation	8
2. Recent Accounting Pronouncements	9
3. Accounts Receivable	9
4. Inventory, Linefill and Base Gas and Long-term Inventory	10
5. Goodwill	10
6. Debt	11
7. Net Income Per Limited Partner Unit	12
8. Partners’ Capital and Distributions	13
9. Equity-Indexed Compensation Plans	14
10. Derivatives and Risk Management Activities	15
11. Commitments and Contingencies	21
12. Operating Segments	23
13. Related Party Transactions	24

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41
Item 4. CONTROLS AND PROCEDURES	43

PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS	44
Item 1A. RISK FACTORS	44
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	44
Item 3. DEFAULTS UPON SENIOR SECURITIES	44
Item 4. MINE SAFETY DISCLOSURES	44
Item 5. OTHER INFORMATION	44
Item 6. EXHIBITS	44
SIGNATURES	45

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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 units)

	March 31,			December 31,
	2014			2013
	(unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	30		$	41
Trade accounts receivable and other receivables, net	3,703			3,638
Inventory	914			1,065
Other current assets	285			220
Total current assets	4,932			4,964

PROPERTY AND EQUIPMENT	12,865			12,473
Accumulated depreciation	(1,713		)	(1,654		)
	11,152			10,819

OTHER ASSETS
Goodwill	2,485			2,503
Linefill and base gas	864			798
Long-term inventory	264			251
Investments in unconsolidated entities	506			485
Other, net	499			540
Total assets	$	20,702		$	20,360

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	4,334		$	3,983
Short-term debt	879			1,113
Other current liabilities	341			315
Total current liabilities	5,554			5,411

LONG-TERM LIABILITIES
Senior notes, net of unamortized discount of $14 and $15, respectively	6,711			6,710
Long-term debt under credit facilities and other	107			5
Other long-term liabilities and deferred credits	547			531
Total long-term liabilities	7,365			7,246

COMMITMENTS AND CONTINGENCIES (NOTE 11)

PARTNERS’ CAPITAL
Common unitholders (362,035,634 and 359,133,200 units outstanding, respectively)	7,419			7,349
General partner	305			295
Total partners’ capital excluding noncontrolling interests	7,724			7,644
Noncontrolling interests	59			59
Total partners’ capital	7,783			7,703
Total liabilities and partners’ capital	$	20,702		$	20,360

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
	March 31,
	2014			2013
	(unaudited)
REVENUES
Supply and Logistics segment revenues	$	11,346		$	10,224
Transportation segment revenues	181			173
Facilities segment revenues	157			223
Total revenues	11,684			10,620

COSTS AND EXPENSES
Purchases and related costs	10,670			9,437
Field operating costs	336			340
General and administrative expenses	89			106
Depreciation and amortization	96			82
Total costs and expenses	11,191			9,965

OPERATING INCOME	493			655

OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	20			11
Interest expense (net of capitalized interest of $11 and $9, respectively)	(78		)	(77		)
Other expense, net	(2		)	—

INCOME BEFORE TAX	433			589
Current income tax expense	(36		)	(46		)
Deferred income tax expense	(12		)	(7		)

NET INCOME	385			536
Net income attributable to noncontrolling interests	(1		)	(8		)
NET INCOME ATTRIBUTABLE TO PAA	$	384		$	528

NET INCOME ATTRIBUTABLE TO PAA:
LIMITED PARTNERS	$	268		$	433
GENERAL PARTNER	$	116		$	95

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.74		$	1.28

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.73		$	1.27

BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	360			336

DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	363			339

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

(in millions)

	Three Months Ended
	March 31,
	2014			2013
	(unaudited)
Net income	$	385		$	536
Other comprehensive loss	(136		)	(46		)
Comprehensive income	249			490
Comprehensive income attributable to noncontrolling interests	(1		)	(5		)
Comprehensive income attributable to PAA	$	248		$	485

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)

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

Reclassification adjustments	20			—			20
Deferred loss on cash flow hedges, net of tax	(32		)	—			(32		)
Currency translation adjustments	—			(124		)	(124		)
Total period activity	(12		)	(124		)	(136		)
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 March 31,
	2014			2013
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	385		$	536
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization	96			82
Equity-indexed compensation expense	34			51
Inventory valuation adjustments	37			—
Deferred income tax expense	12			7
Other	4			(1		)
Changes in assets and liabilities, net of acquisitions	254			304
Net cash provided by operating activities	822			979

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions, net of cash acquired	—			(31		)
Additions to property, equipment and other	(468		)	(363		)
Cash received for sales of linefill and base gas	11			9
Cash paid for purchases of linefill and base gas	(44		)	(13		)
Investment in unconsolidated entities	(26		)	(48		)
Proceeds from sales of assets	2			2
Other investing activities	1			—
Net cash used in investing activities	(524		)	(444		)

CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments under PAA senior secured hedged inventory facility (Note 6)	—			(335		)
Net repayments under PAA senior unsecured revolving credit facility (Note 6)	—			(72		)
Net borrowings under PNG credit agreement	—			27
Net repayments under PAA commercial paper program (Note 6)	(128		)	—
Net proceeds from the issuance of common units (Note 8)	151			131
Distributions paid to common unitholders (Note 8)	(221		)	(189		)
Distributions paid to general partner (Note 8)	(107		)	(85		)
Distributions paid to noncontrolling interests	(1		)	(12		)
Other financing activities	(1		)	—
Net cash used in financing activities	(307		)	(535		)

Effect of translation adjustment on cash	(2		)	—

Net decrease in cash and cash equivalents	(11		)	—
Cash and cash equivalents, beginning of period	41			24
Cash and cash equivalents, end of period	$	30		$	24

Cash paid for:
Interest, net of amounts capitalized	$	78		$	70
Income taxes, net of amounts refunded	$	66		$	9

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
								Excluding
	Common Units				General			Noncontrolling			Noncontrolling			Partners’
	Units	Amount			Partner			Interests			Interests			Capital
	(unaudited)
Balance at December 31, 2013	359.1	$	7,349		$	295		$	7,644		$	59		$	7,703
Net income	—	268			116			384			1			385
Distributions	—	(221		)	(107		)	(328		)	(1		)	(329		)
Issuance of common units	2.8	148			3			151			—			151
Issuance of common units under LTIP, net of units tendered by employees to satisfy tax withholding obligations	0.1	(2		)	—			(2		)	—			(2		)
Equity-indexed compensation expense	—	11			1			12			—			12
Distribution equivalent right payments	—	(1		)	—			(1		)	—			(1		)
Other comprehensive loss	—	(133		)	(3		)	(136		)	—			(136		)
Balance at March 31, 2014	362.0	$	7,419		$	305		$	7,724		$	59		$	7,783

								Partners’ Capital
								Excluding
	Common Units				General			Noncontrolling			Noncontrolling			Partners’
	Units	Amount			Partner			Interests			Interests			Capital
	(unaudited)
Balance at December 31, 2012	335.3	$	6,388		$	249		$	6,637		$	509		$	7,146
Net income	—	433			95			528			8			536
Distributions	—	(189		)	(85		)	(274		)	(12		)	(286		)
Issuance of common units	2.4	128			3			131			—			131
Equity-indexed compensation expense	—	7			—			7			1			8
Distribution equivalent right payments	—	(1		)	—			(1		)	—			(1		)
Other comprehensive loss	—	(42		)	(1		)	(43		)	(3		)	(46		)
Other	—	—			—			—			1			1
Balance at March 31, 2013	337.7	$	6,724		$	261		$	6,985		$	504		$	7,489

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 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 12 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. Plains All American GP LLC (“GP LLC”), a Delaware limited liability company, is AAP’s general partner. 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
Bcf	=	Billion cubic feet
Btu	=	British thermal unit
CAD	=	Canadian dollar
DERs	=	Distribution equivalent rights
EBITDA	=	Earnings before interest, taxes, depreciation and amortization
FASB	=	Financial Accounting Standards Board
GAAP	=	Generally accepted accounting principles in the United States
ICE	=	IntercontinentalExchange
LIBOR	=	London Interbank Offered Rate
LTIP	=	Long-term incentive plan
Mcf	=	Thousand cubic feet
MLP	=	Master limited partnership
NGL	=	Natural gas liquids including ethane, natural gasoline products, propane and butane
NYMEX	=	New York Mercantile Exchange
PLA	=	Pipeline loss allowance
PNG	=	PAA Natural Gas Storage, L.P.
SEC	=	Securities and Exchange Commission
USD	=	United States dollar
White Cliffs	=	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 notes thereto should be read in conjunction with our 2013 Annual Report on Form 10-K. The financial statements have been prepared in accordance with the instructions for interim reporting as set forth by the SEC. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods have been reflected. All significant intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to information from previous years to conform to the current presentation. The condensed consolidated balance sheet data as of December 31, 2013 was derived from audited financial statements, but does not include all disclosures required by GAAP. The results of operations for the three months ended March 31, 2014 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 than as discussed below and in our 2013 Annual Report on Form 10-K, no new accounting pronouncements have become effective or have been issued during the three months ended March 31, 2014 that are of significance or potential significance to us.

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. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

Note 3—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 a rigorous credit review process. We closely monitor market conditions in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, parental guarantees or advance cash payments. As of March 31, 2014 and December 31, 2013, we had received approximately $105 million and $117 million, respectively, of advance cash payments from third parties to mitigate credit risk. Furthermore, as of March 31, 2014 and December 31, 2013, we had received approximately $206 million and $426 million, respectively, of standby letters of credit to support obligations due from third parties, a portion of which applies to future business. In addition, in an effort to mitigate credit risk, a significant portion of our transactions with counterparties are settled on a net-cash basis. Further, we enter into netting agreements (contractual agreements that allow us to offset receivables and payables with those counterparties against each other on our balance sheet) for a majority of such arrangements.

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

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Note 4—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):

	March 31, 2014						December 31, 2013
		Unit of	Carrying		Price/			Unit of	Carrying		Price/
	Volumes	Measure	Value		Unit (1)		Volumes	Measure	Value		Unit (1)
Inventory
Crude oil	7,274	barrels	$	645	$	88.67	6,951	barrels	$	540	$	77.69
NGL	3,846	barrels	181		$	47.06	8,061	barrels	352		$	43.67
Natural gas	12,660	Mcf	61		$	4.82	40,505	Mcf	150		$	3.70
Other	N/A		27		N/A		N/A		23		N/A
Inventory subtotal			914						1,065

Linefill and base gas
Crude oil	11,031	barrels	681		$	61.74	10,966	barrels	679		$	61.92
NGL	1,431	barrels	61		$	42.63	1,341	barrels	62		$	46.23
Natural gas	25,612	Mcf	122		$	4.76	16,615	Mcf	57		$	3.43
Linefill and base gas subtotal			864						798

Long-term inventory
Crude oil	2,655	barrels	214		$	80.60	2,498	barrels	202		$	80.86
NGL	1,210	barrels	50		$	41.32	1,161	barrels	49		$	42.20
Long-term inventory subtotal			264						251

Total			$	2,042					$	2,114

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

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. We recorded a charge of approximately $37 million during the three months ended March 31, 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 three months ended March 31, 2014. This adjustment is a component of “Purchases and related costs” in our accompanying condensed consolidated statements of operations.

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
2014 Goodwill Related Activity:
Foreign currency translation adjustments	(11		)	(5		)	(2		)	(18		)
Balance at March 31, 2014	$	867		$	1,157		$	461		$	2,485

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Note 6—Debt

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

	March 31,		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) (2)	$	876	$	1,109
Other	3		4
Total short-term debt	879		1,113

LONG-TERM DEBT
Senior notes, net of unamortized discounts of $14 and $15, respectively	$	6,711	$	6,710
PAA commercial paper notes, bearing a weighted-average interest rate of 0.30% (2)	102		—
Other	5		5
Total long-term debt	6,818		6,715
Total debt (1) (3)	$	7,697	$	7,828

(1) At March 31, 2014 and December 31, 2013, we classified $876 million and $1.1 billion, respectively, of borrowings under our commercial paper program as short-term. These borrowings are primarily designated as working capital borrowings, must be repaid within one year and are primarily for hedged NGL and crude oil inventory and NYMEX and ICE margin deposits.

(2) PAA commercial paper notes are backstopped by the PAA senior unsecured revolving credit facility and the PAA senior secured hedged inventory facility, which mature in August 2018 and August 2016, respectively; as such, any borrowings under the PAA commercial paper program reduce the available capacity under these facilities. Although our PAA commercial paper notes generally have maturities of less than one year, we classified $102 million of such notes as long-term based on our ability and intent to refinance them on a long-term basis.

(3) Our fixed-rate senior notes had a face value of approximately $6.7 billion at both March 31, 2014 and December 31, 2013. We estimated the aggregate fair value of these notes as of March 31, 2014 and December 31, 2013 to be approximately $7.3 billion and $7.2 billion, respectively. Our fixed-rate senior notes are traded among institutions, and these trades are routinely published by a reporting service. Our determination of fair value is based on reported trading activity near quarter end. We estimate that the carrying value of outstanding borrowings under our credit facilities and agreements and commercial paper program approximates fair value as interest rates reflect current market rates. The fair value estimates for both our senior notes and credit facilities are based upon observable market data and are classified within Level 2 of the fair value hierarchy.

Borrowings and Repayments

Total borrowings under our credit agreements and the commercial paper program for the three months ended March 31, 2014 and 2013 were approximately $19.2 billion and $3.2 billion, respectively. Total repayments under our credit agreements and the commercial paper program were approximately $19.3 billion and $3.6 billion for the three months ended March 31, 2014 and 2013, 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 March 31, 2014 and December 31, 2013, we had outstanding letters of credit of approximately $70 million and $41 million, respectively.

Senior Notes Issuance

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. 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. See Note 10 for additional disclosure.

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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 the 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.

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

Diluted net income per limited partner unit is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method. Our LTIP awards that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. See Note 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 earnings per limited partner unit for the three months ended March 31, 2014 and 2013 (in millions, except per unit data):

	Three Months Ended March 31,
	2014			2013
Basic Net Income per Limited Partner Unit
Net income attributable to PAA	$	384		$	528
Less: General partner’s incentive distribution (1)	(110		)	(86		)
Less: General partner 2% ownership (1)	(6		)	(9		)
Net income available to limited partners	268			433
Less: Undistributed earnings allocated and distributions to participating securities (1)	(2		)	(3		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	266		$	430

Basic weighted average number of limited partner units outstanding	360			336

Basic net income per limited partner unit	$	0.74		$	1.28

Diluted Net Income per Limited Partner Unit
Net income attributable to PAA	$	384		$	528
Less: General partner’s incentive distribution (1)	(110		)	(86		)
Less: General partner 2% ownership (1)	(6		)	(9		)
Net income available to limited partners	268			433
Less: Undistributed earnings allocated and distributions to participating securities (1)	(2		)	(1		)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	266		$	432

Basic weighted average number of limited partner units outstanding	360			336
Effect of dilutive securities: Weighted average LTIP units	3			3
Diluted weighted average number of limited partner units outstanding	363			339

Diluted net income per limited partner unit	$	0.73		$	1.27

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(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.

The terms of our partnership agreement limit the general partner’s incentive distribution to the amount 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 earnings per limited partner unit as reflected in the table above would be impacted as follows:

	Three Months Ended March 31,
	2014			2013
Basic net income per limited partner unit impact	$	(0.05	)	$	(0.34	)

Diluted net income per limited partner unit impact	$	(0.05	)	$	(0.34	)

Note 8—Partners’ Capital and Distributions

Distributions

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

		Distributions Paid								Distributions
		Common		General Partner						per limited
Date Declared	Date Paid or To Be Paid	Units		Incentive		2%		Total		partner unit
April 7, 2014	May 15, 2014 (1)	$	229	$	110	$	5	$	344	$	0.6300
January 9, 2014	February 14, 2014	$	221	$	102	$	5	$	328	$	0.6150

(1) Payable to unitholders of record at the close of business on May 2, 2014 for the period January 1, 2014 through March 31, 2014.

Continuous Offering Program

During the three months ended March 31, 2014, we issued an aggregate of approximately 2.8 million common units under our continuous offering program, generating proceeds of approximately $151 million, including our general partner’s proportionate capital contribution, net of approximately $1 million of commissions to our sales agents.

Noncontrolling Interests in Subsidiaries

As of March 31, 2014, noncontrolling interests in 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 (the “PNG Merger”).

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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.

PAA LTIP Awards. Our equity-indexed compensation activity for LTIP awards denominated in PAA units 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	0.6		$	45.02
Vested (2)	(0.1	)	$	34.78
Cancelled or forfeited	(0.1	)	$	38.07
Outstanding at March 31, 2014	8.8		$	37.55

(1) Amounts do not include AAP Management Units.

(2) Approximately 0.1 million PAA common units were issued, net of tax withholding of less than 0.1 million units, during the three months ended March 31, 2014 in connection with the settlement of vested awards. The remaining PAA awards that vested during the three months ended March 31, 2014 (less than 0.1 million units) were settled in cash.

AAP Management Units. The following table contains a summary of AAP Management Units (in millions):

	Reserved for Future Grants		Outstanding	Outstanding Units Earned	Grant Date Fair Value Of Outstanding AAP Management Units (1)
Balance as of December 31, 2013	3.5		48.6	47.0	$	51
Granted	(0.4	)	0.4	—	11
Earned	N/A		N/A	0.3	N/A
Balance as of March 31, 2014	3.1		49.0	47.3	$	62

(1) Of the grant date fair value, approximately $1 million was recognized as expense during the three months ended March 31, 2014. Of the $62 million grant date fair value, approximately $50 million had been recognized through March 31, 2014.

Other Equity-Indexed Compensation Information. The table below summarizes the expense recognized and the value of vesting (settled both in units and cash) related to our equity-indexed compensation plans and includes both liability-classified and equity-classified awards (in millions):

	Three Months Ended
	March 31,
	2014		2013
Equity-indexed compensation expense	$	34	$	51
LTIP unit-settled vestings	$	5	$	—
LTIP cash-settled vestings	$	1	$	—
DER cash payments	$	2	$	2

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

· An average of 272,000 barrels per day net long position (total of 8.2 million barrels) associated with our crude oil purchases, which was unwound ratably during April 2014 to match monthly average pricing.

· A net short spread position averaging approximately 24,700 barrels per day (total of 9.8 million barrels), which hedges a portion of our anticipated crude oil lease gathering purchases through May 2015. These derivatives are time spreads consisting of offsetting purchases and sales between two different months. Our use of these derivatives does not expose us to outright price risk.

· An average of 2,900 barrels per day (total of 1.1 million barrels) of butane/WTI spread positions, which hedge specific butane sales contracts that are priced as a percentage of WTI through March 2015.

· An average of 19,000 barrels per day (total of 1.2 million barrels) of Brent/WTI spread positions, which hedge purchases based on WTI derived indices and sales based on Brent derived indices through June 2014.

· A long position of approximately 2.1 Bcf through April 2016 related to anticipated base gas requirements.

· A short position of approximately 12.6 Bcf through July 2014 related to anticipated sales of natural gas inventory.

· A net short position of approximately 5.0 million barrels through March 2015 related to the anticipated sales of our crude oil, NGL and refined products inventory.

Storage Capacity Utilization — We own a significant amount of crude oil, NGL and refined products storage capacity other than that used in our transportation operations. This storage may be leased to third parties or utilized in our own supply and logistics activities, including for the storage of inventory in a contango market. For capacity allocated to our supply and logistics operations, we have utilization risk in a backwardated market structure. As of March 31, 2014, we used derivatives to manage the risk of not utilizing approximately 0.5 million barrels of storage capacity through June 2014. These positions involve no outright price exposure, but instead enable us to profitably use the capacity to store hedged crude oil.

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 March 31, 2014, our PLA hedges included a net short position for an average of approximately 1,800 barrels per day (total of 1.1 million barrels) through December 2015 and a long call option position of approximately 0.4 million barrels through December 2015.

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Natural Gas Processing/NGL Fractionation — As part of our supply and logistics activities, we purchase natural gas for processing and 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 March 31, 2014, we had a long natural gas position of approximately 21.8 Bcf through December 2015, a short propane position of approximately 3.8 million barrels through December 2015, a short butane position of approximately 1.2 million barrels through December 2015 and a short WTI position of approximately 0.4 million barrels through December 2015. In addition, we had a long power position of 0.7 million megawatt hours which hedges a portion of our power supply requirements at our natural gas processing and fractionation plants through December 2016.

All of our commodity derivatives that qualify for hedge accounting are designated as cash flow hedges. We have determined that substantially all of our physical purchase and sale agreements qualify for the 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 normal sale scope exception are recorded on the balance sheet at fair value, with changes in fair value recognized in earnings.

Interest Rate Risk Hedging

We use interest rate derivatives to hedge interest rate risk associated with anticipated debt issuances and outstanding debt instruments. The derivative instruments we use to manage this risk consist primarily of interest rate swaps and treasury locks. As of March 31, 2014, AOCI includes deferred losses of approximately $83 million that relate to open and terminated interest rate derivatives that were designated for hedge accounting. The terminated interest rate derivatives were cash-settled in connection with the issuance or refinancing of debt agreements. The deferred loss related to these instruments is being amortized to interest expense over the terms of the hedged debt instruments.

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

Hedged Transaction

Number and Types of
Derivatives Employed

Notional
Amount

Expected
Termination Date

Average Rate
Locked

Accounting
Treatment

Anticipated debt offering

10 forward starting swaps (30-year)

250

6/15/2015

3.60

Cash flow hedge

In anticipation of our April 2014 issuance of senior notes, we entered into four treasury lock agreements in March 2014 for a combined notional amount of $200 million at a locked in rate of 3.64%. In addition, we entered into a treasury lock agreement in April 2014 for a notional amount of $50 million. 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 approximately $7 million. The effective portion of the treasury locks will be deferred in AOCI and amortized to interest expense over the life of the senior notes.

Currency Exchange Rate Risk Hedging

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

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

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

		USD		CAD		Average Exchange Rate USD to CAD
Forward exchange contracts that exchange CAD for USD:
	2014	$	265	$	293	$1.00 - $1.11
	2015	9		10		$1.00 - $1.11
		$	274	$	303	$1.00 - $1.11

Forward exchange contracts that exchange USD for CAD:
	2014	$	265	$	291	$1.00 - $1.10
	2015	9		9		$1.00 - $1.06
		$	274	$	300	$1.00 - $1.10

Net position by currency:
	2014	$	—	$	2
	2015	—		1
		$	—	$	3

Summary of Financial Impact

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

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

	Three Months Ended March 31, 2014											Three Months Ended March 31, 2013
	Derivatives in Hedging Relationships											Derivatives in Hedging Relationships
Location of gain/(loss)	Gain/(loss) reclassified from AOCI into income			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	$	(19	)	$	—	$	—		$	(19	)	$	10		$	—	$	35	$	45

Facilities segment revenues	—			—		—			—			(4		)	—		—		(4		)

Field operating costs	—			—		(1		)	(1		)	—			—		1		1

Interest Rate Derivatives

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

Foreign Currency Derivatives

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

Other expense, net	—			—		—			—			1			—		—		1

Total Gain/(Loss) on Derivatives Recognized in Net Income	$	(20	)	$	—	$	(10	)	$	(30	)	$	5		$	—	$	36	$	41

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(1) During the three months ended March 31, 2013 we reclassified a gain of approximately $2 million from AOCI to Supply and Logistics segment revenues as a result of anticipated hedged transactions that are probable of not occurring. During the three months ended March 31, 2014, all of our hedged transactions were probable of occurring.

The following table summarizes the derivative assets and liabilities on our condensed consolidated balance sheet on a gross basis as of March 31, 2014 (in millions):

	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
Derivatives designated as hedging instruments:
Commodity derivatives	Other current assets	$	56	Other current assets	$	(10	)
	Other long-term assets	4		Other long-term assets	(1		)
Interest rate derivatives	Other long-term assets	8		Other current liabilities	(1		)
				Other long-term liabilities	(1		)
Total derivatives designated as hedging instruments		$	68		$	(13	)

Derivatives not designated as hedging instruments:
Commodity derivatives	Other current assets	$	71	Other current assets	$	(64	)
	Other long-term assets	1		Other long-term assets	(1		)
	Other current liabilities	1		Other current liabilities	(1		)
				Other long-term liabilities	(1		)
Foreign currency derivatives				Other current liabilities	(3		)
Total derivatives not designated as hedging instruments		$	73		$	(70	)

Total derivatives		$	141		$	(83	)

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.

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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 March 31, 2014, we had a net broker receivable of approximately $43 million (consisting of initial margin of $65 million reduced by $22 million of variation margin that had been returned to us). As of December 31, 2013, we had a net broker receivable of approximately $161 million (consisting of initial margin of $85 million increased by $76 million of variation margin that had been posted by us).

The following tables present information about derivatives and financial assets and liabilities that are subject to offsetting, including enforceable master netting arrangements at March 31, 2014 and December 31, 2013 (in millions):

	March 31, 2014						December 31, 2013
	Derivative			Derivative			Derivative			Derivative
	Asset Positions			Liability Positions			Asset Positions			Liability Positions

Netting Adjustments:
Gross position - asset/(liability)	$	141		$	(83	)	$	133		$	(157	)
Netting adjustment	(77		)	77			(148		)	148
Cash collateral paid/(received)	43			—			161			—
Net position - asset/(liability)	$	107		$	(6	)	$	146		$	(9	)

Balance Sheet Location After Netting Adjustments:
Other current assets	$	96		$	—		$	116		$	—
Other long-term assets	11			—			30			—
Other current liabilities	—			(4		)	—			(8		)
Other long-term liabilities	—			(2		)	—			(1		)
	$	107		$	(6	)	$	146		$	(9	)

As of March 31, 2014, there was a net loss of approximately $89 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 March 31, 2014, we expect to reclassify a net gain of approximately $1 million to earnings in the next twelve months. The remaining deferred loss of approximately $90 million is expected to be reclassified to earnings through 2045. A portion of these amounts are based on market prices as of March 31, 2014; thus, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

	Three Months Ended
	March 31,
	2014			2013
Commodity derivatives, net	$	(12	)	$	3
Interest rate derivatives, net	(20		)	19
Total	$	(32	)	$	22

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

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Recurring Fair Value Measurements

Derivative Financial Assets and Liabilities

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

	Fair Value as of March 31, 2014										Fair Value as of December 31, 2013
Recurring Fair Value Measures (1)	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3			Total
Commodity derivatives	$	46	$	8		$	1	$	55		$	16	$	(59	)	$	(3	)	$	(46	)
Interest rate derivatives	—		6			—		6			—		26			—			26
Foreign currency derivatives	—		(3		)	—		(3		)	—		(4		)	—			(4		)
Total net derivative asset/(liability)	$	46	$	11		$	1	$	58		$	16	$	(37	)	$	(3	)	$	(24	)

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

Level 1

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

Level 2

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

Level 3

Level 3 of the fair value hierarchy includes over-the-counter commodity derivatives that are traded in markets that are active but not sufficiently active to warrant level 2 classification in our judgment and certain physical commodity contracts. The fair value of our level 3 over-the-counter commodity derivatives is based on broker price quotations. The fair value of our level 3 physical commodity contracts is based on a valuation model utilizing broker-quoted forward commodity prices, and timing estimates, which involve management judgment. The significant unobservable inputs used in the fair value measurement of our level 3 derivatives are forward prices obtained from brokers. A significant increase (decrease) in these forward prices would result in a proportionately lower (higher) fair value measurement.

Rollforward of Level 3 Net Asset

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

	Three Months Ended
	March 31,
	2014			2013
Beginning Balance	$	(3	)	$	4
Unrealized gains/(losses):
Included in earnings (1)	—			—
Included in other comprehensive income	—			—
Settlements	3			(3		)
Derivatives entered into during the period	1			—
Transfers out of level 3	—			—
Ending Balance	$	1		$	1

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

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

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

Note 11—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.

Pemex Exploración y Producción v. Big Star Gathering Ltd L.L.P. et al (the “Big Star Lawsuit”) and Pemex Exploración y Producción v. Murphy Energy et al (the “Murphy Lawsuit”). In two cases filed in the Texas Southern District Court in May 2011 and April 2012, Pemex Exploración y Producción (“PEP”) alleges that certain parties stole condensate from pipelines and gathering stations and conspired with U.S. companies (primarily in Texas) to import and market the stolen condensate. PEP does not allege that Plains was part of any conspiracy, but that it dealt in the condensate only after it had been obtained by others and resold to Plains Marketing, L.P. PEP seeks actual damages, attorney’s fees, and statutory penalties from Plains Marketing, L.P. In February 2013, the Court granted Plains Marketing, L.P.’s motion to be dismissed from the Murphy Lawsuit. In October 2013, the Court issued an order in the Big Star Lawsuit granting summary judgment in favor of Plains Marketing, L.P. with respect to all of PEP’s remaining claims against Plains Marketing, L.P. In February 2014, the Court affirmed its order granting summary judgment in favor of Plains Marketing, L.P. in the Big Star Lawsuit, denied PEP’s motion for reconsideration, severed the case against Plains from the other defendants and issued a final judgment dismissing all claims against Plains. The time for PEP to appeal the final judgment in the Big Star case has lapsed. Plains’ motion to sever Plains from the remainder of the defendants in the Murphy Lawsuit in order to obtain a final judgment is pending.

PNG Merger. Purported class action lawsuits were filed on behalf of PNG unitholders challenging the PNG Merger. Two lawsuits were filed in the Delaware Court of Chancery in September 2013 and were consolidated under the caption In re PAA Natural Gas Storage, Limited Partnership Unitholder Litigation, C.A. No. 8908-VCL (which we refer to as the Consolidated Delaware Action). Two lawsuits were filed in Texas state court in September 2013 and were consolidated under the caption Vicars v. PNGS GP, LLC, et al., Cause No. 2013-52687 (Tex. Dist. Ct. Harris County) (which we refer to as the Consolidated Texas Action). Four lawsuits were filed in Texas federal court in October 2013 and were consolidated under the caption The DuckPond Trust, et al., v. PAA Natural Gas Storage, LP., et al., 4:13-cv-03170 (S.D. Tex.) (which we refer to as the Consolidated Federal Action).

Plaintiffs in these Actions generally alleged that (i) the individual defendants breached fiduciary duties owed to PNG unitholders; (ii) the PNG Merger unfairly benefitted certain members of PNG’s board of directors; and (iii) PNG’s general partner, PNG and other of our affiliates aided and abetted the alleged fiduciary breaches by the individual defendants. In addition, the Consolidated Texas Action included purported derivative claims on behalf of PNG based on the alleged breaches of duties by the individual defendants. All of the PNG unitholder suits were voluntarily dismissed by the plaintiffs with no settlement payments or concessions by PNG.

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Environmental

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

At March 31, 2014, our estimated undiscounted reserve for environmental liabilities totaled approximately $91 million, of which approximately $12 million was classified as short-term and approximately $79 million was classified as long-term. At December 31, 2013, our estimated undiscounted reserve for environmental liabilities totaled approximately $93 million, of which approximately $11 million was classified as short-term and approximately $82 million was classified as long-term. The short- and long-term environmental liabilities referenced above are reflected in “Accounts payable and accrued liabilities” and “Other long-term liabilities and deferred credits,” respectively, on our condensed consolidated balance sheets. At both March 31, 2014 and December 31, 2013, we had recorded receivables totaling approximately $10 million for amounts probable of recovery under insurance and from third parties under indemnification agreements, which are predominantly reflected in “Trade accounts receivable and other receivables, net” on our condensed consolidated balance sheets.

In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves are based on information currently available to us and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment and the possibility of existing legal claims giving rise to additional 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.

Rainbow Pipeline Release. During April 2011, we experienced a crude oil release of approximately 28,000 barrels of crude oil on a remote section of our Rainbow Pipeline located in Alberta, Canada. Since the release and through March 31, 2014, we spent approximately $70 million, before insurance recoveries, in connection with site clean-up, reclamation and remediation activities, and as of March 31, 2014, we did not have any material outstanding liabilities or insurance receivables relating to this release. On February 26, 2013, the Alberta Energy Regulator (“AER”) issued four enforcement actions against PMC for failure to comply with certain regulatory requirements in connection with the release, including requirements related to operations and maintenance procedures, leak detection and response, backfill and compaction procedures and emergency response plan testing. PMC is in the process of taking appropriate actions necessary to respond to and comply with the enforcement actions set forth in the report, including the implementation of additional risk assessment procedures and the taking of other actions designed to minimize the risk that similar incidents occur in the future and enhance the effectiveness of PMC’s response to any such future incidents. In addition, on April 23, 2013, the Alberta Crown Prosecutor filed civil charges under the Environmental Protection and Enhancement Act against PMC relating to the release. To date, PMC has not been assessed any fines or penalties related to this release; however, such fines or penalties may be assessed in the future.

Rangeland Pipeline Release. During June 2012, we experienced a crude oil release on a section of our Rangeland Pipeline located near Sundre, Alberta, Canada. Approximately 3,000 barrels were released into the Red Deer River and were contained downstream in the Gleniffer Reservoir. Remediation activities in the reservoir area were completed by June 30, 2012, remediation of the remaining impacted areas of government-owned lands was completed by September 30, 2012 and interim closure, in respect of those lands, was received from the applicable regulatory agencies. A long-term monitoring plan has been developed and implemented in accordance with regulatory requirements. Through March 31, 2014, we spent approximately $46 million, before insurance recoveries, in connection with site clean-up, reclamation and remediation activities. On July 4, 2013, the AER issued four enforcement actions against PMC citing failure to inspect water crossings, failure to complete an engineering assessment to determine suitability of continued operation of the Rangeland Pipeline, failure to maintain updated emergency response plans, and failure to conduct regular public awareness programs. To date, no charges, fines or penalties have been assessed against PMC with respect to this release; however, it is possible that fines or penalties may be assessed against PMC in the future.

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 oil was contained within our pipeline right of way, but some of the released 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, and we may be subjected to a civil penalty. The aggregate cost to clean up and remediate the site was approximately $6 million.

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Kemp River Pipeline Release. 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 investigation is not complete. To date, no charges, fines or penalties have been assessed against PMC with respect to this release; 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.

Note 12—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) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative expenses. Each of the items above excludes depreciation and amortization. Maintenance capital consists of capital expenditures for the replacement of partially or fully depreciated assets in order to maintain the operating and/or earnings capacity of our existing assets. The following table reflects certain financial data for each segment for the periods indicated (in millions):

	Transportation		Facilities		Supply and Logistics		Total
Three Months Ended March 31, 2014
Revenues (1):
External Customers	$	181	$	157	$	11,346	$	11,684
Intersegment (2)	206		142		22		370
Total revenues of reportable segments	$	387	$	299	$	11,368	$	12,054
Equity earnings in unconsolidated entities	$	20	$	—	$	—	$	20
Segment profit (3) (4)	$	206	$	154	$	249	$	609
Maintenance capital	$	34	$	10	$	2	$	46

Three Months Ended March 31, 2013
Revenues:
External Customers	$	173	$	223	$	10,224	$	10,620
Intersegment (2)	195		131		1		327
Total revenues of reportable segments	$	368	$	354	$	10,225	$	10,947
Equity earnings in unconsolidated entities	$	11	$	—	$	—	$	11
Segment profit (3) (4)	$	164	$	150	$	434	$	748
Maintenance capital	$	32	$	7	$	5	$	44

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

(2) Segment revenues and purchases and related costs include intersegment amounts. Intersegment sales are conducted at posted tariff rates, rates similar to those charged to third parties or rates that we believe approximate market. For further discussion, see “Analysis of Operating Segments” under Item 7 of our 2013 Annual Report on Form 10-K.

(3) Supply and Logistics segment profit includes interest expense (related to hedged inventory purchases) of approximately $2 million and $5 million for the three months ended March 31, 2014 and 2013, respectively.

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

	For the Three Months
	Ended March 31,
	2014			2013
Segment profit	$	609		$	748
Depreciation and amortization	(96		)	(82		)
Interest expense, net	(78		)	(77		)
Other expense, net	(2		)	—
Income tax expense	(48		)	(53		)
Net income	385			536
Net income attributable to noncontrolling interests	(1		)	(8		)
Net income attributable to PAA	$	384		$	528

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Note 13—Related Party Transactions

See Note 14 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for a complete discussion of our related party transactions.

Occidental Petroleum Corporation

As of March 31, 2014, a subsidiary of Occidental Petroleum Corporation (“Oxy”) owned approximately 25% of our general partner and had a representative on the board of directors of GP LLC. During the three months ended March 31, 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
	March 31,
	2014		2013
Revenues	$	92	$	269

Purchases and related costs	$	259	$	161

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

	March 31,		December 31,
	2014		2013
Trade accounts receivable and other receivables	$	161	$	133

Accounts payable	$	233	$	181

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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 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 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 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. 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. 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.

Overview of Operating Results, Capital Investments and Significant Activities

During the first three months of 2014, we recognized net income attributable to PAA of approximately $384 million, or $0.73 per diluted limited partner unit, as compared to net income attributable to PAA of approximately $528 million, or $1.27 per diluted limited partner unit, recognized during the first three months of 2013. These decreases were primarily driven by less favorable crude oil market conditions experienced during the comparable 2014 period, which provided fewer opportunities for above-baseline crude oil margins in our Supply and Logistics segment. In addition, our Facilities and Supply and Logistics segments were negatively impacted by costs incurred in our natural gas storage activities to manage deliverability requirements in conjunction with the severe cold weather experienced during the first quarter of 2014. However, such decreases were partially offset by favorable results from our Transportation segment, largely due to the continued increase in North American crude oil production and our related, recently completed capital expansion projects.

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Acquisitions and Internal Growth Projects

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

	Three Months
	Ended March 31,
	2014		2013
Acquisition capital	$	—	$	1
Internal growth projects	563		358
Maintenance capital	46		44
Total	$	609	$	403

Internal Growth Projects

The following table summarizes our more notable projects in progress during 2014 and the forecasted expenditures for the year ending December 31, 2014 (in millions):

Projects		2014
Permian Basin Area Projects		$470
Cactus Pipeline		330
Rail Terminal Projects (1)		215
Ft. Sask Facility Projects / NGL Line		160
Eagle Ford JV Project		70
Western Oklahoma Extension		65
Mississippian Lime Pipeline		50
White Cliffs Expansion		40
Line 63 Reactivation		40
Natural Gas Storage Expansions		25
Other Projects		385
		$1,850
Potential Adjustments for Timing / Scope Refinement (2)		-$100 + $100
Total Projected Expansion Capital Expenditures		$1,750 - $1,950

(1) Includes projects located in or near Bakersfield, CA; Carr, CO; Van Hook, ND; and Western Canada.

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

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Results of Operations

Analysis of Operating Segments

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

	Three Months						Favorable/ (Unfavorable)
	Ended March 31,						Variance
	2014			2013			$			%
Transportation segment profit	$	206		$	164		$	42		26	%
Facilities segment profit	154			150			4			3	%
Supply and Logistics segment profit	249			434			(185		)	(43	)%
Total segment profit	609			748			(139		)	(19	)%
Depreciation and amortization	(96		)	(82		)	(14		)	(17	)%
Interest expense, net	(78		)	(77		)	(1		)	(1	)%
Other expense, net	(2		)	—			(2		)	N/A
Income tax expense	(48		)	(53		)	5			9	%
Net income	385			536			(151		)	(28	)%
Net income attributable to noncontrolling interests	(1		)	(8		)	7			88	%
Net income attributable to PAA	$	384		$	528		$	(144	)	(27	)%

Net income attributable to PAA:
Basic net income per limited partner unit	$	0.74		$	1.28		$	(0.54	)	(42	)%
Diluted net income per limited partner unit	$	0.73		$	1.27		$	(0.54	)	(42	)%
Basic weighted average units outstanding	360			336			24			7	%
Diluted weighted average units outstanding	363			339			24			7	%

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), (iii) items that are not indicative of our core operating results and business outlook and/or (iv) 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 and footnotes.

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

	Three Months						Favorable/ (Unfavorable)
	Ended March 31,						Variance
	2014			2013			$			%
Net income	$	385		$	536		$	(151	)	(28	)%
Add:
Depreciation and amortization	96			82			14			17	%
Income tax expense	48			53			(5		)	(9	)%
Interest expense, net	78			77			1			1	%
EBITDA	$	607		$	748		$	(141	)	(19	)%

Selected Items Impacting Comparability of EBITDA
Gains/(losses) from derivative activities net of inventory valuation adjustments(1)	$	65		$	24		$	41		171	%
Equity-indexed compensation expense (2)	(19		)	(24		)	5			21	%
Net gain/(loss) on foreign currency revaluation (3)	(5		)	8			(13		)	(163	)%
Other (4)	(1		)	1			(2		)	(200	)%
Selected Items Impacting Comparability of EBITDA	$	40		$	9		$	31		344	%

EBITDA	$	607		$	748		$	(141	)	(19	)%
Selected Items Impacting Comparability of EBITDA	(40		)	(9		)	(31		)	(344	)%
Adjusted EBITDA	$	567		$	739		$	(172	)	(23	)%

Adjusted EBITDA	$	567		$	739		(172		)	(23	)%
Interest expense, net	(78		)	(77		)	(1		)	(1	)%
Maintenance capital (5)	(46		)	(44		)	(2		)	(5	)%
Current income tax expense	(36		)	(46		)	10			22	%
Equity earnings in unconsolidated entities, net of distributions	5			—			5			N/A
Distributions to noncontrolling interests (6)	(1		)	(12		)	11			92	%
Implied DCF	$	411		$	560		$	(149	)	(27	)%
Less: Distributions paid (6)	(344		)	(285		)
DCF Excess/(Shortage) (7)	$	67		$	275

(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. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. See Note 10 to our condensed consolidated financial statements for a comprehensive discussion regarding our derivatives and risk management activities.

(2) 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 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for a comprehensive discussion regarding our equity-indexed compensation plans.

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(3) During the three months ended March 31, 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) Includes other immaterial selected items impacting comparability.

(5) 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.

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

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

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 and other transportation fees.

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

	Three Months						Favorable/(Unfavorable)
Operating Results (1)	Ended March 31,						Variance
(in millions, except per barrel amounts)	2014			2013			$			%
Revenues
Tariff activities	$	336		$	320		$	16		5	%
Trucking	51			48			3			6	%
Total transportation revenues	387			368			19			5	%

Costs and Expenses
Trucking costs	(37		)	(35		)	(2		)	(6	)%
Field operating costs (excluding equity-indexed compensation expense)	(129		)	(131		)	2			2	%
Equity-indexed compensation expense - operations (2)	(4		)	(9		)	5			56	%
Segment general and administrative expenses (3) (excluding equity-indexed compensation expense)	(22		)	(23		)	1			4	%
Equity-indexed compensation expense - general and administrative (2)	(9		)	(17		)	8			47	%
Equity earnings in unconsolidated entities	20			11			9			82	%
Segment profit	$	206		$	164		$	42		26	%
Maintenance capital	$	34		$	32		$	(2	)	(6	)%
Segment profit per barrel	$	0.60		$	0.50		$	0.10		20	%

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	Three Months		Favorable/(Unfavorable)
Average Daily Volumes	Ended March 31,		Variance
(in thousands of barrels per day) (4)	2014	2013	Volumes		%
Tariff activities
Crude Oil Pipelines
All American	33	40	(7	)	(18	)%
Bakken Area Systems	131	123	8		7	%
Basin / Mesa	745	725	20		3	%
Capline	126	156	(30	)	(19	)%
Eagle Ford Area Systems	189	48	141		294	%
Line 63 / Line 2000	125	118	7		6	%
Manito	45	47	(2	)	(4	)%
Mid-Continent Area Systems	315	291	24		8	%
Permian Basin Area Systems	760	477	283		59	%
Rainbow	120	122	(2	)	(2	)%
Rangeland	69	67	2		3	%
Salt Lake City Area Systems	131	135	(4	)	(3	)%
South Saskatchewan	64	60	4		7	%
White Cliffs	23	22	1		5	%
Other	661	734	(73	)	(10	)%
NGL Pipelines
Co-Ed	57	57	—		—	%
Other	116	207	(91	)	(44	)%
Refined Products Pipelines	—	101	(101	)	(100	)%
Tariff activities total	3,710	3,530	180		5	%
Trucking	130	111	19		17	%
Transportation segment total	3,840	3,641	199		5	%

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

(2) Equity-indexed compensation expense shown in the table above includes expenses associated with awards that will or may be settled in units and awards that will or may be settled in cash. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional discussion regarding our equity-indexed compensation plans.

(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 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.

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 leases generally reflects a negotiated amount.

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

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, 2014 compared to the three months ended March 31, 2013. Our Transportation segment results for the comparative periods were impacted by the following:

· North American Crude Oil Production and Related Expansion Projects — For the three months ended March 31, 2014, we experienced favorable volume and revenue variances due to increased producer drilling activities as well as the completion of certain of our expansion projects, most notably on our Permian Basin and Eagle Ford Area Systems and our Basin and Mesa pipelines. The Permian Basin Area Systems also benefited from increased movements to a new third-party pipeline connected to Gulf Coast markets. We estimate that increased production combined with our phased-in expansion projects increased revenues by approximately $22 million for the three months ended March 31, 2014 compared to the three months ended March 31, 2013.

· Loss Allowance Revenue — As is common in the 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 approximately $10 million for the three months ended March 31, 2014 compared to three months ended March 31, 2013 driven by higher volumes, as well as a higher average realized price per barrel (including the impact of gains and losses from derivative-related activities).

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· 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 months ended March 31, 2014, our revenues and volumes were lower by approximately $10 million and 101,000 barrels per day, respectively, as compared to the three months ended March 31, 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 March 31, 2014 and 2013 were $1.10 CAD: $1.00 USD and $1.01 CAD: $1.00 USD, respectively. Therefore, revenues from our Canadian pipeline systems and trucking operations were unfavorably impacted by approximately $8 million for the three months ended March 31, 2014 compared to the three months ended March 31, 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 months ended March 31, 2014 compared to the three months ended March 31, 2013 are (i) decreased volumes and revenues on certain of our NGL pipelines due to the discontinuation of an agreement in 2014 to transport volumes on such pipelines and netting joint venture related volumes to our share on a certain pipeline in 2014, which did not impact revenues, (ii) increased volumes and revenues from our new Mississippian Lime pipeline, which was placed into service in the third quarter of 2013, (iii) decreased volumes and revenues on our Capline pipeline due to refinery turnaround in the first quarter of 2014, (iv) decreased volumes and revenues on our All American pipeline due to maintenance issues and (v) a net decrease in volumes on our crude oil pipelines included in “Other” in the table above, a majority of which is related to (a) pipelines subject to long-term lease commitments with annual service payments whereby volumes may fluctuate, but such fluctuations do not have a meaningful impact on revenue and (b) pipelines impacted by third-party connection shut-downs and line repairs, which also did not have a significant impact on revenues for the period.

Equity-Indexed Compensation Expense. On a consolidated basis across all segments, equity-indexed compensation expense decreased for the three months ended March 31, 2014 compared to the three months ended March 31, 2013, primarily due to a less significant impact of the increase in unit price during the three months ended March 31, 2014 compared to the three months ended March 31, 2013. 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.

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Equity Earnings in Unconsolidated Entities. The favorable variance in equity earnings in unconsolidated entities for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was largely due to increased throughput on the Eagle Ford pipeline as a result of increased production, as discussed 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.

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

	Three Months						Favorable/(Unfavorable)
Operating Results (1)	Ended March 31,						Variance
(in millions, except per barrel amounts)	2014			2013			$			%
Revenues	$	299		$	267		$	32		12	%
Natural gas sales (2)	—			87			(87		)	(100	)%
Storage related costs (natural gas related)	(26		)	(6		)	(20		)	(333	)%
Natural gas sales costs (2)	—			(84		)	84			100	%
Field operating costs (excluding equity-indexed compensation expense)	(97		)	(86		)	(11		)	(13	)%
Equity-indexed compensation expense - operations (3)	(1		)	(1		)	—			—	%
Segment general and administrative expenses (4) (excluding equity-indexed compensation expense)	(13		)	(17		)	4			24	%
Equity-indexed compensation expense - general and administrative (3)	(8		)	(10		)	2			20	%
Segment profit	$	154		$	150		$	4		3	%
Maintenance capital	$	10		$	7		$	(3	)	(43	)%
Segment profit per barrel	$	0.42		$	0.42		$	—		—	%

	Three Months		Favorable/(Unfavorable)
	Ended March 31,		Variance
Volumes (5)	2014	2013	Volumes		%
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)	95	94	1		1	%
Rail load / unload volumes (average volumes in thousands of barrels per day)	229	216	13		6	%
Natural gas storage (average monthly capacity in billions of cubic feet)	97	93	4		4	%
NGL fractionation (average volumes in thousands of barrels per day)	92	100	(8	)	(8	)%
Facilities segment total (average monthly volumes in millions of barrels) (6)	121	119	2		2	%

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

(2) Effective January 1, 2014, our natural gas sales and costs, primarily attributable to the activities performed by our natural gas storage commercial optimization group, are reported in the Supply and Logistics segment.

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(3) Equity-indexed compensation expense shown in the table above includes expenses associated with awards that will or may be settled in units and awards that will or may be settled in cash. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional discussion regarding our equity-indexed compensation plans.

(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 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.

Operating Revenues and Volumes. As noted in the table above, our Facilities segment revenues, less storage related costs, and volumes increased for the comparative period presented. The significant variances in revenues and average monthly volumes between the comparative periods are primarily due to our ongoing acquisition and expansion activities as discussed below:

· NGL Fractionation, NGL Storage and Gas Processing Activities —Revenues from our NGL fractionation and storage and gas processing activities increased by approximately $23 million for the three months ended March 31, 2014 compared to the three months ended March 31, 2013. This increase was largely driven by increased facility fees and higher processing gains related to the component mix of the products. NGL fractionation volumes, however, were lower during the first quarter of 2014 relative to the comparative period primarily related to reduced streams of NGL mix supply at certain of our facilities that resulted in decreased production rates.

This favorable revenue variance was partially offset by unfavorable foreign exchange impact of approximately $6 million. The average CAD to USD exchange rates for the three months ended March 31, 2014 and 2013 were $1.10 CAD: $1.00 USD and $1.01 CAD: $1.00 USD, respectively. Therefore, revenues from our Canadian operations in our Facilities segment were unfavorably impacted for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 due to the depreciation of the Canadian dollar relative to the U.S. dollar.

· Natural Gas Storage Operations — Net revenues from our natural gas storage operations decreased by approximately $12 million for the three months ended March 31, 2014 compared to the three months ended March 31, 2013, primarily due to 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.

· Rail Terminals — Revenue and volumes from rail load and unload activities increased by approximately $3 million and 13,300 barrels per day, respectively, for the three months ended March 31, 2014 compared to the three months ended March 31, 2013. These increases were primarily due to new rail terminals that came online in the fourth quarter of 2013, partially offset by the unfavorable impact of weather-related issues at certain of our terminals.

Field Operating Costs. Field operating costs (excluding equity-indexed compensation expenses) increased during the three months ended March 31, 2014 compared to the three months ended March 31, 2013 due to (i) growth in our rail terminal operations, resulting in increased operating expenses, (ii) increased utility costs due primarily to higher power and gas prices and (iii) a change in classification of costs from General and Administrative Expenses.

General and Administrative Expenses. General and administrative expenses (excluding equity-indexed compensation expenses) decreased during the three months ended March 31, 2014 compared to the three months ended March 31, 2013 primarily due to a change in classification of costs to Field Operating Costs.

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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 months ended March 31, 2014 compared to the three months ended March 31, 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 decreased during the three months ended March 31, 2014 compared to the three months ended March 31, 2013. See the discussion regarding such variances under “— Transportation Segment” above. Also, see Note 15 to our condensed 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.

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.

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

	Three Months						Favorable/(Unfavorable)
Operating Results (1)(2)	Ended March 31,						Variance
(in millions, except per barrel amounts)	2014			2013			$			%
Revenues	$	11,368		$	10,225		$	1,143		11	%
Purchases and related costs (3)	(10,975		)	(9,636		)	(1,339		)	(14	)%
Field operating costs (excluding equity-indexed compensation expense)	(106		)	(115		)	9			8	%
Equity-indexed compensation expense - operations (4)	(1		)	(1		)	—			—	%
Segment general and administrative expenses (5) (excluding equity-indexed compensation expense)	(26		)	(26		)	—			—	%
Equity-indexed compensation expense - general and administrative (4)	(11		)	(13		)	2			15	%
Segment profit	$	249		$	434		$	(185	)	(43	)%
Maintenance capital	$	2		$	5		$	3		60	%
Segment profit per barrel	$	2.37		$	4.21		$	(1.84	)	(44	)%

	Three Months						Favorable/(Unfavorable)
Average Daily Volumes	Ended March 31,						Variance
(in thousands of barrels per day)	2014			2013			Volumes			%
Crude oil lease gathering purchases	893			857			36			4	%
NGL sales	273			284			(11		)	(4	)%
Waterborne cargos	—			4			(4		)	(100	)%
Supply and Logistics segment total	1,166			1,145			21			2	%

(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 approximately $2 million and $5 million for the three months ended March 31, 2014 and 2013, respectively.

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(4) Equity-indexed compensation expense shown in the table above includes expenses associated with awards that will or may be settled in units and awards that will or may be settled in cash. See Note 15 to our Consolidated Financial Statements included in Part IV of our 2013 Annual Report on Form 10-K for additional discussion regarding our equity-indexed compensation plans.

(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.

The NYMEX West Texas Intermediate benchmark price of crude oil ranged from approximately $92 to $105 per barrel and $89 to $98 per barrel during the three months ended March 31, 2014 and 2013, respectively. 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 for the three months ended March 31, 2014 relative to the comparative period, resulting from increases in prices and volumes in 2014.

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.

Operating Revenues and Volumes. Our Supply and Logistics segment revenues, net of purchases and related costs and excluding gains and losses from derivative activities (see the “Impact from Derivative Activities” section below), decreased year-over-year for the comparative periods presented. The increasing production of oil and liquids-rich gas in North America over the last several years generally created supply and demand imbalances that increased the volatility of historical differentials for various grades of crude oil and also impacted the historical pricing relationship between NGL and crude oil. Lack of existing pipeline takeaway capacity and associated logistical challenges in certain of these producing regions created market conditions and opportunities that were favorable to our supply and logistics activities. During the first quarter of 2013, these conditions provided opportunities for increased margins. However, infrastructure additions in many of these resource plays during 2013 began to relieve certain of the transportation constraints that had created opportunities for these favorable crude oil margins. Therefore, although we experienced higher crude oil lease gathering volumes in the first quarter of 2014 compared to the first quarter of 2013, we experienced fewer opportunities to capture favorable location differentials. Additionally, our natural gas storage commercial optimization activities were unfavorably impacted by costs incurred to manage deliverability requirements in conjunction with the extended period of severe cold weather experienced during the first quarter of 2014.

We believe the fundamentals of our business remain strong; however, as the midstream infrastructure in these producing regions 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.)

Impact from Derivative Activities. The mark-to-market valuation of our derivative activities impacted our net revenues as shown in the table below (in millions):

	Three Months
	Ended March 31,
	2014		2013		Variance
Gains from derivative activities (1)	$	66	$	24	$	42

(1) Includes mark-to-market and other gains and losses resulting from derivative instruments that are related to underlying activities in future periods or the reversal of mark-to-market gains and losses from the prior period. These amounts are reduced by the net impact of 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. See Note 10 to our condensed consolidated financial statements for a comprehensive discussion regarding our derivatives and risk management activities.

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Field Operating Costs. The decrease in field operating costs (excluding equity-indexed compensation expenses) for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was primarily due to lower third-party transportation costs as we shift our volumes to pipelines.

Equity-Indexed Compensation Expense. On a consolidated basis across all segments, equity-indexed compensation expense decreased for the three months ended March 31, 2014 as compared to the three months ended March 31, 2013. See the discussion regarding such variances under “— Transportation Segment” above. Also, 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.

Other Income and Expenses

Depreciation and Amortization

Depreciation and amortization expense was approximately $96 million for the three months ended March 31, 2014 compared to approximately $82 million for the three months ended March 31, 2013. The increase in depreciation and amortization expense during the 2014 period over the comparable 2013 was primarily due to an acceleration of depreciation on certain pipeline assets to reflect a change in their estimated useful lives, as well as various internal growth projects completed since March 31, 2013.

Income Tax Expense

Income tax expense decreased by approximately $5 million for the three months ended March 31, 2014, compared to the three months ended March 31, 2013, primarily as a result of higher taxable income in the prior period.

Net Income attributable to Noncontrolling Interests

Net income attributable to noncontrolling interests decreased for the three months ended March 31, 2014 compared to the three months ended March 31, 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 the commercial paper program or the 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 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 the commercial paper program or the 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 March 31, 2014, we had a working capital deficit of approximately $622 million and approximately $2.0 billion of liquidity available to meet our ongoing operating, investing and financing needs as noted below (in millions):

	As of March 31, 2014
Availability under PAA senior unsecured revolving credit facility (1)	$	1,558
Availability under PAA senior secured hedged inventory facility (1)	1,372
Less: Amounts outstanding under PAA commercial paper program	(978		)
Subtotal	1,952
Cash and cash equivalents	30
Total	$	1,982

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(1) Represents availability prior to giving effect to amounts outstanding under the PAA commercial paper program. Borrowings under the PAA commercial paper program reduce available capacity under the facility.

We believe that we have and will continue to have the ability to access 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 “Risk Factors” in Item 1A of our 2013 Annual Report on Form 10-K for further discussion regarding such risks that may impact our liquidity and capital resources. Usage of the credit facilities, which provide the backstop for the commercial paper program, is subject to ongoing compliance with covenants. As of March 31, 2014, 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, see “Liquidity and Capital Resources-Cash Flow from Operating Activities” under Item 7 of our 2013 Annual Report on Form 10-K.

Net cash provided by operating activities for the first three months of 2014 was approximately $822 million, primarily resulting from earnings from our operations. Additionally, during the first three months of 2014, we decreased the amount 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.

Net cash provided by operating activities for the first three months of 2013 of approximately $979 million also resulted primarily from earnings from our operations. In addition, we decreased the amount of our inventory during the first quarter of 2013, primarily due to the sale of NGL inventory related to product demand caused by increases in (i) heating requirements during the 2013 winter season, (ii) export activity that reduced overall product availability in the market and (iii) petrochemical demand. The net proceeds received from liquidation of such inventory during the quarter were used to repay borrowings under our credit facilities and favorably impacted our cash flow from operating activities.

Acquisitions and Capital Expenditures

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

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

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 by operations and the financing activities discussed below.

Equity and Debt Financing Activities

Our financing activities primarily relate to funding acquisitions, internal capital projects and refinancing 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 the commercial paper program or the credit facilities, as well as payment of distributions to our unitholders and general partner.

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Registration 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 March 31, 2014, we had approximately $1.3 billion 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, subject to market conditions and our capital needs.

Continuous Offering Program. During the three months ended March 31, 2014, we issued an aggregate of approximately 2.8 million common units under our continuous offering program, generating net proceeds of approximately $151 million, including our general partner’s proportionate capital contribution of approximately $3 million. The net proceeds from these sales were used for general partnership purposes.

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 March 31, 2014.

During the three months ended March 31, 2014 and 2013, we had net repayments on our credit agreements (which include our revolving credit facility and hedged inventory facility) and commercial paper program of approximately $128 million and $380 million, respectively. The repayments during both periods were primarily driven by cash flow from operating activities, including sales of NGL inventory that was liquidated during the periods, as well as cash received from common units issued under our continuous offering program.

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 approximately $691 million to repay outstanding borrowings under our commercial paper program and for general partnership purposes.

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 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 February 14, 2014, we paid a quarterly distribution of $0.6150 per limited partner unit, which represented a 9.3% increase over the distribution we paid in February 2013. Additionally, on May 15, 2014, we will pay a distribution of $0.6300 per limited partner unit, which represents a 9.6% increase over the distribution we paid in May 2013. See Note 8 to our 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 Annual Report on Form 10-K for additional discussion on distributions.

Distributions to noncontrolling interests. We paid approximately $1 million and $12 million for distributions to noncontrolling interests during the three months ended March 31, 2014 and 2013, respectively. The decrease in amounts paid is due to our completion of the PNG Merger 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 11 to our condensed consolidated financial statements.

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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 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 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 March 31, 2014 (in millions):

	Remainder of 2014		2015		2016		2017		2018		2019 and Thereafter		Total
Long-term debt, including related interest payments (1)	$	265	$	894	$	500	$	695	$	867	$	7,350	$	10,571
Leases (2)	115		140		123		102		77		386		943
Other obligations (3)	209		98		60		41		24		140		572
Subtotal	589		1,132		683		838		968		7,876		12,086
Crude oil, natural gas, NGL and other purchases (4)	10,196		6,220		5,599		3,999		2,480		7,972		36,466
Total	$	10,785	$	7,352	$	6,282	$	4,837	$	3,448	$	15,848	$	48,552

(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.

(3) Includes (i) other long-term liabilities, (ii) storage and transportation agreements and (iii) 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 approximately $2 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 March 2014. 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 March 31, 2014 and December 31, 2013, we had outstanding letters of credit of approximately $70 million and $41 million, respectively.

Off-Balance Sheet Arrangements

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

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Recent Accounting Pronouncements

See Note 2 to our condensed consolidated financial statements.

Critical Accounting Policies and Estimates

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

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 or other factors;

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

· tightened capital markets or other factors that increase our cost of capital or limit our access to capital;

· 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;

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

· the effectiveness of our risk management activities;

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

· 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;

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· 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;

· 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 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.

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.

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.

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· NGL

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. We manage these exposures with various instruments including exchange-traded and over-the-counter futures, forwards, swaps and options.

See Note 10 to our condensed consolidated financial statements for further discussion regarding our hedging strategies and objectives.

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 March 31, 2014 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%
	Fair Value		Price Increase			Price Decrease
Crude oil and related products	$	38	$	25		$	(24	)
Natural gas	1		$	4		$	(4	)
NGL and other	16		$	(10	)	$	10
Total fair value	$	55

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 variable rate debt at March 31, 2014, approximately $978 million, is subject to interest rate re-sets, which range from one week to three months. The average interest rate of approximately 0.3% is based upon rates in effect during the first three months ended March 31, 2014. The fair value of our interest rate derivatives is an asset of approximately $6 million as of March 31, 2014. A 10% increase in the forward LIBOR curve as of March 31, 2014 would result in an increase of approximately $18 million to the fair value of our interest rate derivatives. A 10% decrease in the forward LIBOR curve as of March 31, 2014 would result in a decrease of approximately $18 million to the fair value of our interest rate derivatives. See Note 10 to our 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 approximately $3 million as of March 31, 2014. A 10% increase in the exchange rate (USD-to-CAD) would result in a decrease of approximately $19 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 approximately $19 million to the fair value of our foreign currency derivatives. See Note 10 to our condensed consolidated financial statements for a discussion of our currency exchange rate risk hedging.

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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.

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 the end of the period covered by this report, and has found 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.

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 have been no changes in our internal control over financial reporting during the period covered by this report 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.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The information required by this item is included under the caption “Litigation” in Note 11 to our 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 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.

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.

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SIGNATURES

Pursuant to the requirements 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:	PLAINS AAP, L.P., its sole member
	By:	PLAINS ALL AMERICAN GP LLC, its general partner

Date: May 9, 2014

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


Date: May 9, 2014

	By:	/s/ Al Swanson
		Al Swanson, Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer)

Date: May 9, 2014

	By:	/s/ Chris Herbold
		Chris Herbold, Vice President- Accounting and
		Chief Accounting Officer
		(Principal Accounting Officer)

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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 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 Current Report on Form 8-K filed October 2, 2012).

3.3	—	Amendment No. 2 dated December 31, 2013 to Fourth Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the 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 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 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 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 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. (incorporated by reference to Exhibit 3.8 to the 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 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 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 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 Current Report on Form 8-K filed October 25, 2013).

3.13	—	Amendment No. 1 dated December 31, 2013 to Seventh Amended and Restated Limited Partnership Agreement of Plains AAP, L.P. (incorporated by reference to Exhibit 3.2 to the 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 Annual Report on Form 10-K for the year ended December 31, 2006).

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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 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 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 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 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 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 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 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 Current Report on Form 8-K filed October 30, 2006).

4.7	—	Thirteenth Supplemental Indenture (Series A and Series B 6.5% 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 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 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 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 Current Report on Form 8-K filed July 13, 2010).

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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 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 and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the 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 and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the 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 by reference to Exhibit 4.1 to the 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 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 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 Current Report on Form 8-K filed April 29, 2014).

12.1 †	—	Computation of Ratio of Earnings to Fixed 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

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

101.INS†	—	XBRL Instance Document

101.SCH†	—	XBRL Taxonomy Extension Schema Document

101.CAL†	—	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF†	—	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB†	—	XBRL Taxonomy Extension Label Linkbase Document

101.PRE†	—	XBRL Taxonomy Extension Presentation Linkbase Document

† Filed herewith.

†† Furnished herewith.