8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

CURRENT REPORT

Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported) — May 6, 2013

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE	1-14569	76-0582150
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

333 Clay Street, Suite 1600, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: 713-646-4100

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Explanatory Note

On May 6, 2013 Plains All American Pipeline, L.P. furnished a Current Report on Form 8-K.  This amendment is being furnished to correct a typographical error contained in subsection C of Note 2 in the previously furnished report.  The Supply and Logistics Segment Profit per Barrel ($/Bbl) Excluding Selected Items Impacting Comparability for the six month period ending December 31, 2013 should be $1.14 instead of $0.76 as stated in the previous Form 8-K.  This amount has been corrected in this amended Form 8-K.  There were no other changes made to the previous Form 8-K or the exhibits thereto.

Item 9.01.Financial Statements and Exhibits

(d)    Exhibit 99.1 — Press Release dated May 6, 2013

Item 2.02 and Item 7.01. Results of Operations and Financial Condition; Regulation FD Disclosure

Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its first quarter 2013 results. We are furnishing the press release, attached as Exhibit 99.1, pursuant to Item 2.02 and Item 7.01 of Form 8-K.  Pursuant to Item 7.01, we are also providing second quarter and second half of 2013 detailed guidance for financial performance.  In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 2.02 and Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Exchange Act or Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Disclosure of Second Quarter and Second Half 2013 Guidance

We based our guidance for the three-month period ending June 30, 2013 and six-month and twelve-month periods ending December 31, 2013 on assumptions and estimates that we believe are reasonable, given our assessment of historical trends (modified for changes in market conditions), business cycles and other reasonably available information. Projections covering multi-quarter periods contemplate inter-period changes in future performance resulting from new expansion projects, seasonal operational changes (such as NGL sales) and acquisition synergies. Our assumptions and future performance, however, are both subject to a wide range of business risks and uncertainties, so no assurance can be provided that actual performance will fall within the guidance ranges. Please refer to information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties, as well as other unforeseeable risks and uncertainties, could cause our actual results to differ materially from those in the following table. The operating and financial guidance provided below is given as of the date hereof, based on information known to us as of May 5, 2013. We undertake no obligation to publicly update or revise any forward-looking statements.

To supplement our financial information presented in accordance with GAAP, management uses additional measures known as “non-GAAP financial measures” in its evaluation of past performance and prospects for the future.  Management believes that the presentation of such additional financial measures provides useful information to investors regarding our financial condition and results of operations because these measures, when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operations 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.  EBIT and EBITDA (each as defined below in Note 1 to the “Operating and Financial Guidance” table) are non-GAAP financial measures. Net income represents one of the two most directly comparable GAAP measures to EBIT and EBITDA. In Note 9 below, we reconcile net income to EBIT and EBITDA for the 2013 guidance periods presented. Cash flow from operating activities is the other most comparable GAAP measure. We do not, however, reconcile cash flows from operating activities to EBIT and EBITDA, because such reconciliations are impractical for a forecasted period. We encourage you to visit our website at www.paalp.com (in particular the section entitled “Non-GAAP Reconciliations”), which presents a historical reconciliation of EBIT and EBITDA as well as certain other commonly used non-GAAP financial measures. In addition, within our guidance, we have highlighted the impact of (i) equity compensation expense, (ii) tax effect on selected items impacting comparability, (iii) net gain on foreign currency revaluation, (iv) gains from derivative activities and (v) other selected items impacting comparability.  Due to the nature of the selected items, certain of the selected items impacting comparability may impact certain non-GAAP financial measures but not impact other non-GAAP financial measures.

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Plains All American Pipeline, L.P.

Operating and Financial Guidance

(in millions, except per unit data)

	Actual			Guidance (a)
	3 Months			3 Months Ending						6 Months Ending						12 Months Ending
	Ended			June 30, 2013						December 31, 2013						December 31, 2013
	March 31, 2013			Low			High			Low			High			Low			High
Segment Profit
Net revenues (including equity earnings from unconsolidated entities)	$	1,194		$	832		$	860		$	1,771		$	1,813		$	3,797		$	3,867
Field operating costs	(340		)	(343		)	(335		)	(676		)	(664		)	(1,359		)	(1,339		)
General and administrative expenses	(106		)	(90		)	(86		)	(166		)	(160		)	(362		)	(352		)
	748			399			439			929			989			2,076			2,176
Depreciation and amortization expense	(82		)	(87		)	(82		)	(178		)	(173		)	(347		)	(337		)
Interest expense, net	(77		)	(82		)	(77		)	(169		)	(164		)	(328		)	(318		)
Income tax benefit (expense)	(53		)	(7		)	(2		)	(23		)	(18		)	(83		)	(73		)
Other income, net	—			1			1			2			2			3			3
Net Income	536			224			279			561			636			1,321			1,451
Less: Net income attributable to noncontrolling interests	(8		)	(6		)	(6		)	(17		)	(17		)	(31		)	(31		)
Net Income Attributable to Plains	$	528		$	218		$	273		$	544		$	619		$	1,290		$	1,420
Net Income to Limited Partners (b)	$	433		$	126		$	180		$	344		$	418		$	903		$	1,030
Basic Net Income Per Limited Partner Unit (b)
Weighted Average Units Outstanding	336			340			340			342			342			340			340
Net Income Per Unit	$	1.28		$	0.37		$	0.53		$	1.00		$	1.21		$	2.64		$	3.01
Diluted Net Income Per Limited Partner Unit (b)
Weighted Average Units Outstanding	339			342			342			345			345			343			343
Net Income Per Unit	$	1.27		$	0.36		$	0.52		$	0.99		$	1.21		$	2.62		$	2.99
EBIT	$	666		$	313		$	358		$	753		$	818		$	1,732		$	1,842
EBITDA	$	748		$	400		$	440		$	931		$	991		$	2,079		$	2,179
Selected Items Impacting Comparability
Equity compensation expense	$	(24	)	$	(15	)	$	(15	)	$	(25	)	$	(25	)	$	(64	)	$	(64	)
Tax effect on selected items impacting comparability	(5		)	—			—			—			—			(5		)	(5		)
Net gain on foreign currency revaluation	8			—			—			—			—			8			8
Gains from derivative activities	24			—			—			—			—			24			24
Other	1			—			—			1			1			2			2
Selected Items Impacting Comparability of Net Income attributable to Plains	$	4		$	(15	)	$	(15	)	$	(24	)	$	(24	)	$	(35	)	$	(35	)
Excluding Selected Items Impacting Comparability
Adjusted Segment Profit
Transportation	$	175		$	180		$	190		$	440		$	455		$	795		$	820
Facilities	156			135			145			294			309			585			610
Supply and Logistics	407			99			119			219			249			725			775
Other income, net	1			1			1			3			3			5			5
Adjusted EBITDA	$	739		$	415		$	455		$	956		$	1,016		$	2,110		$	2,210
Adjusted Net Income Attributable to Plains	$	524		$	233		$	288		$	568		$	643		$	1,325		$	1,455
Adjusted Basic Net Income Per Limited Partner Unit (b)	$	1.27		$	0.41		$	0.57		$	1.07		$	1.28		$	2.74		$	3.11
Adjusted Diluted Net Income Per Limited Partner Unit (b)	$	1.26		$	0.41		$	0.56		$	1.06		$	1.27		$	2.72		$	3.10

(a)

The projected average foreign exchange rate is $1.00 Canadian to $1.00 U.S. for the three-month period ending June 30, 2013 and the six-month period ending December 31, 2013. The rate as of May 3, 2013 was $1.00 Canadian to $0.99 U.S. A $0.05 change in the FX rate will impact annual adjusted EBITDA by approximately $14 million.

(b)

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.

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Notes and Significant Assumptions:

1. Definitions.

EBIT	Earnings before interest and taxes
EBITDA	Earnings before interest, taxes and depreciation and amortization expense
Segment Profit	Net revenues (including equity earnings, as applicable) less field operating costs and segment general and administrative expenses
DCF	Distributable Cash Flow
FASB	Financial Accounting Standards Board
Bbls/d	Barrels per day
Bcf	Billion cubic feet
LTIP	Long-Term Incentive Plan
NGL	Natural gas liquids. Includes ethane and natural gasoline products as well as propane and butane, which are often referred to as liquefied petroleum gas (LPG). When used in this document NGL refers to all NGL products including LPG.
FX	Foreign currency exchange
General partner (GP)	As the context requires, “general partner” refers to any or all of (i) PAA GP LLC, the owner of our 2% general partner interest, (ii) Plains AAP, L.P., the sole member of PAA GP LLC and owner of our incentive distribution rights and (iii) Plains All American GP LLC, the general partner of Plains AAP, L.P.

2.Operating Segments. We manage our operations through three operating segments: (i) Transportation, (ii) Facilities and (iii) Supply and Logistics. The following is a brief explanation of the operating activities for each segment as well as key metrics.

a.Transportation. Our Transportation segment operations generally consist of fee-based activities associated with transporting crude oil, NGL and refined products on pipelines, gathering systems, trucks and barges. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity and transportation fees. Our transportation segment also includes our equity earnings from our investments in Settoon Towing and the White Cliffs, Butte, Frontier and Eagle Ford pipeline systems, in which we own non-controlling interests.

Pipeline volume estimates are based on historical trends, anticipated future operating performance and assumed completion of internal growth projects. Actual volumes will be influenced by maintenance schedules at refineries, production trends, weather and other natural occurrences including hurricanes, changes in the quantity of inventory held in tanks, and other external factors beyond our control. We forecast adjusted segment profit using the volume assumptions in the table below, priced at forecasted tariff rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation. Actual segment profit could vary materially depending on the level and mix of volumes transported or expenses incurred during the period. The following table summarizes our total transportation volumes and highlights major systems that are significant either in total volumes transported or in contribution to total Transportation segment profit.

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	Actual		Guidance
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	Mar 31, 2013		Jun 30, 2013			Dec 31, 2013			Dec 31, 2013
Average Daily Volumes (MBbls/d)
Crude Oil / Refined Products Pipelines
All American	40		35			35			36
Bakken Area Systems	123		130			135			131
Basin/Mesa	725		700			710			711
Capline	156		160			150			154
Eagle Ford Area Systems	48		75			155			109
Line 63 / 2000	118		110			110			112
Manito	47		45			45			45
Mid-Continent Area Systems	268		270			275			272
Permian Basin Area Systems	477		545			635			574
Rainbow	122		125			125			124
Rangeland	67		60			65			64
Salt Lake City Area Systems	135		145			150			145
White Cliffs	22		20			25			23
Other	918		895			830			868
NGL Pipelines
Co-Ed	57		55			60			58
Other	207		175			185			188
	3,530		3,545			3,690			3,614
Trucking	111		135			130			127
	3,641		3,680			3,820			3,741
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability	$	0.53	$	0.55	1	$	0.64	1	$	0.59	1

(1)Mid-point of guidance.

b.Facilities. 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. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements.

Revenues generated in this segment include (i) storage fees that are generated when we lease storage capacity, (ii) terminal throughput fees that are generated when we receive crude oil, refined products or NGL from one connecting source and redeliver the applicable product to another connecting carrier, (iii) loading and unloading fees at our rail terminals, (iv) hub service fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services, (v) revenues from the sale of natural gas, (vi) fees from NGL fractionation and isomerization and (vii) fees from gas and condensate processing services. Adjusted segment profit is forecasted using the volume assumptions in the table below, priced at forecasted rates, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

	Actual		Guidance
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	Mar 31, 2013		Jun 30, 2013			Dec 31, 2013			Dec 31, 2013
Operating Data
Crude Oil, Refined Products, and NGL Terminalling and Storage (MMBbls/Mo.)	94		95			95			95
Rail Unload / Load Volumes (MBbl/d)	216		250			340			287
Natural Gas Storage (Bcf/Mo.)	93		97			97			96
NGL Fractionation (MBbls/d)	100		95			105			101
Facilities Activities Total Avg. Capacity (MMBbls/Mo.) ¹	119		122			125			123
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability	$	0.44	$	0.38	2	$	0.40	2	$	0.40	2

(1)Calculated as the sum of: (i) crude oil, refined products and NGL terminalling and storage capacity; (ii) rail load and unload volumes, multiplied by the number of days in the period and divided by the number of months in the period; (iii) natural gas storage 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

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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.

(2)Mid-point of guidance.

c.Supply and Logistics. Our Supply and Logistics segment operations generally consist of the following merchant-related activities:

·the purchase of U.S. and Canadian crude oil at the wellhead, the bulk purchase of crude oil at pipeline, terminal and rail facilities, and the purchase of cargos at their load port and various other locations in transit;

·the storage of inventory during contango market conditions and the seasonal storage of NGL;

·the purchase of NGL from producers, refiners, processors and other marketers;

·the resale or exchange of crude oil and NGL at various points along the distribution chain to refiners or other resellers to maximize profits; and

·the transportation of crude oil and NGL on trucks, barges, railcars, pipelines and ocean-going vessels to various delivery points, including but not limited to refineries, connecting carriers and fractionation facilities.

We characterize a substantial portion of our baseline profit generated by our Supply and Logistics segment as fee equivalent. This portion of the segment profit is generated by the purchase and resale of crude oil on an index-related basis, which results in us generating a gross margin for such activities.  This gross margin is reduced by the transportation, facilities and other logistical costs associated with delivering the crude oil to market as well as any operating and general and administrative expenses.  The level of profit associated with a portion of the other activities we conduct in the Supply and Logistics segment is influenced by overall market structure and the degree of volatility in the crude oil market, as well as variable operating expenses. Forecasted operating results for the three-month period ending June 30, 2013 reflect the current market structure and for the six-month period ending December 31, 2013 reflect the seasonal, weather-related variations in NGL sales.  Variations in weather, market structure or volatility could cause actual results to differ materially from forecasted results.

We forecast adjusted segment profit using the volume assumptions stated below, as well as estimates of unit margins, field operating costs, G&A expenses and carrying costs for contango inventory, based on current and anticipated market conditions. Actual volumes are influenced by temporary market-driven storage and withdrawal of oil, maintenance schedules at refineries, actual production levels, weather, and other external factors beyond our control. Field operating costs do not include depreciation. Realized unit margins for any given lease-gathered barrel could vary significantly based on a variety of factors including location and quality differentials as well as contract structure. Accordingly, the projected segment profit per barrel can vary significantly even if aggregate volumes are in line with the forecasted levels.

	Actual		Guidance
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	Mar 31, 2013		Jun 30, 2013			Dec 31, 2013			Dec 31, 2013
Average Daily Volumes (MBbl/d)
Crude Oil Lease Gathering Purchases	857		880			930			900
NGL Sales	284		125			185			194
Waterborne Cargos	4		5			5			5
	1,145		1,010			1,120			1,099
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability	$	3.95	$	1.19	1	$	1.14	1	$	1.87	1

(1)Mid-point of guidance.

3.Depreciation and Amortization. We forecast depreciation and amortization based on our existing depreciable assets, forecasted capital expenditures and projected in-service dates. Depreciation may vary due to gains and losses on intermittent sales of assets, asset retirement obligations, asset impairments or foreign exchange rates.

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4.Capital Expenditures and Acquisitions.  Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions that we may commit to after the date hereof. We forecast capital expenditures during calendar 2013 to be approximately $1.4 billion for expansion projects with an additional $170 to $190 million for maintenance capital projects.  During the first three months of 2013, we spent $358 million and $44 million for expansion and maintenance projects, respectively.  The following are some of the more notable projects and forecasted expenditures for the year ending December 31, 2013: 

	Calendar 2013
	(in millions)
Expansion Capital
· Mississippian Lime Pipeline	$180
· Rainbow II Pipeline	130
· Eagle Ford JV Project	95
· Rail Terminal Projects (1)	90
· White Cliffs Expansion	90
· Gulf Coast Pipeline	90
· Yorktown Terminal Projects	80
· Eagle Ford Area Pipeline Projects	75
· St. James Terminal Projects	55
· Cactus Pipeline	50
· PAA Natural Gas Storage (Multiple Projects)	42
· Spraberry Area Pipeline Projects	40
· Western Oklahoma Extension	40
· Shafter Expansion	25
· Cushing Terminal Projects	20
· Other Projects (2)	298
	$1,400
Potential Adjustments for Timing / Scope Refinement (3)	- $50        + $150
Total Projected Expansion Capital Expenditures	$1,350   -   $1,550
Maintenance Capital Expenditures	$170     -     $190

(1)Includes projects located at or near Tampa, CO, Bakersfield, CA, Carr, CO and Van Hook, ND.

(2)Primarily multiple, smaller projects comprised of pipeline connections, upgrades and truck stations, new tank construction and refurbishing, pipeline linefill purchases and carry-over of projects from prior years.

(3)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.

5.Capital Structure. This guidance is based on our capital structure as of March 31, 2013 and adjusted for estimated equity issuances under our continuous offering program.  Also assumed in our guidance is that we expect to repay our $250 million 5.625% senior notes that mature December 15, 2013 with short-term borrowings from our credit facility as a result of prefunding during 2012 (equity and retained cash flow), accordingly these notes are classified as short-term on our balance sheet at March 31, 2013.

6.Interest Expense. Debt balances are projected based on estimated cash flows, estimated distribution rates, estimated capital expenditures for maintenance and expansion projects, anticipated equity proceeds from the continuous offering program, expected timing of collections and payments and forecasted levels of inventory and other working capital sources and uses. Interest rate assumptions for variable-rate debt are based on the LIBOR curve as of late April.

Included in interest expense are commitment fees, amortization of long-term debt discounts or premiums, deferred amounts associated with terminated interest-rate hedges and interest on short-term debt for non-contango inventory (primarily hedged NGL inventory and New York Mercantile Exchange and Intercontinental Exchange margin deposits). Interest expense is net of amounts capitalized for major expansion capital projects and does not include interest on borrowings for inventory stored in a contango market. We treat interest on hedged inventory borrowings as carrying costs of crude oil and NGL and include it in purchases and related costs.

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7.Income Taxes. We expect our Canadian income tax expense to be approximately $5 million and $78 million for the three-month period ending June 30, 2013 and twelve-month period ending December 31, 2013, of which approximately $(1) million and $49 million, respectively, is classified as current income tax expense (benefit).  For the twelve-month period ending December 31, 2013 we expect to have a deferred tax expense of $29 million.  All or part of the income tax expense of $78 million may result in a tax credit to our equity holders.

8.Equity Compensation Plans. The majority of grants outstanding under our various equity compensation plans contain vesting criteria that are based on a combination of performance benchmarks and service periods. The grants will vest in various percentages, typically on the later to occur of specified vesting dates and the dates on which minimum distribution levels are reached. Among the various grants outstanding as of May 5, 2013, estimated vesting dates range from May 2013 to August 2019 and annualized benchmark distribution levels range from $1.925 to $2.85. For some awards, a percentage of any units remaining unvested as of a certain date will vest on such date and all others will be forfeited.

On April 8, 2013, we declared an annualized distribution of $2.30 payable on May 15, 2013 to our unitholders of record as of May 3, 2013. For the purposes of guidance, we have made the assessment that a $2.50 distribution level is probable of occurring, and accordingly, guidance includes an accrual over the applicable service period at an assumed market price of $56.00 per unit as well as an accrual associated with awards that will vest on a certain date. The actual amount of equity compensation expense in any given period will be directly influenced by (i) our unit price at the end of each reporting period, (ii) our unit price on the vesting date, (iii) the probability assessment regarding distributions, and (iv) new equity compensation award grants. For example, a $2.00 change in the unit price would change the second-quarter and full-year equity compensation expense by approximately $6 million and $7 million, respectively. Therefore, actual net income could differ from our projections.

9.Reconciliation of Net Income to EBIT, EBITDA and Adjusted EBITDA. The following table reconciles net income to EBIT, EBITDA and Adjusted EBITDA for the three-month period ending June 30, 2013 and the six and twelve-month periods ending December 31, 2013.

	Guidance
	3 Months Ending				6 Months Ending				12 Months Ending
	June 30, 2013				December 31, 2013				December 31, 2013
	Low		High		Low		High		Low		High
Reconciliation to EBITDA
Net Income	$	224	$	279	$	561	$	636	$	1,321	$	1,451
Interest expense, net	82		77		169		164		328		318
Income tax expense	7		2		23		18		83		73
EBIT	313		358		753		818		1,732		1,842
Depreciation and amortization	87		82		178		173		347		337
EBITDA	$	400	$	440	$	931	$	991	$	2,079	$	2,179
Selected Items Impacting Comparability of EBITDA	15		15		25		25		31		31
Adjusted EBITDA	$	415	$	455	$	956	$	1,016	$	2,110	$	2,210

10.  Implied DCF. The following table reconciles the mid-point of adjusted EBITDA to implied DCF for the three-month period ending June 30, 2013 and the six and twelve-month periods ending December 31, 2013.

	Mid-Point Guidance
	Three Months			Six Months			Twelve Months
	Ending			Ending			Ending
	June 30, 2013			December 31, 2013			December 31, 2013
	(in millions)
Adjusted EBITDA	$	435		$	986		$	2,160
Interest expense, net	(80		)	(166		)	(323		)
Current income tax benefit (expense)	1			(4		)	(49		)
Distributions to noncontrolling interests	(13		)	(26		)	(51		)
Maintenance capital expenditures	(45		)	(91		)	(180		)
Implied DCF	$	298		$	699		$	1,557

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Forward-Looking Statements and Associated Risks

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, however, does not mean that the statements are not forward-looking. These 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 to differ materially from results 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);

·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;

·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 effectiveness of our risk management activities;

·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 or slowdown in the development of additional oil and gas reserves or other factors;

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

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

·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;

·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;

·interruptions in service on third-party pipelines;

·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;

9

·the currency exchange rate of the Canadian dollar;

·weather interference with business operations or project construction;

·risks related to the development and operation of natural gas storage 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.

We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, which information is incorporated by reference herein.

10

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 hereunto 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 7, 2013	By:	/s/ Charles Kingswell-Smith
		Name:	Charles Kingswell-Smith
		Title:	Vice President and Treasurer

11

EX-99.1

Exhibit 99.1

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. Reports

Strong First-Quarter 2013 Results

(Houston — May 6, 2013) Plains All American Pipeline, L.P. (NYSE: PAA) reported strong first-quarter 2013 results as summarized below:

Summary Financial Information(1)

(in millions, except per unit data)

	Three Months Ended March 31,
	2013		2012		% Change
Net income attributable to Plains	$	528	$	230	130%
Diluted net income per limited partner unit	$	1.27	$	0.51	149%
EBITDA	$	748	$	382	96%

	Three Months Ended March 31,
	2013		2012		% Change
Adjusted net income attributable to Plains	$	524	$	320	64%
Diluted adjusted net income per limited partner unit	$	1.26	$	0.79	59%
Adjusted EBITDA	$	739	$	472	57%
Distribution declared for the period	$	0.5750	$	0.5225	10.0%

(1)    The Partnership’s reported results include the impact of items that affect comparability between reporting periods. The impact of these items is excluded from adjusted results. See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding selected items that the Partnership believes impact comparability of financial results between reporting periods, as well as for information regarding non-GAAP financial measures (such as adjusted EBITDA) and their reconciliation to the most directly comparable GAAP measures.

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“PAA reported very strong first-quarter results, which meaningfully exceeded 2012’s comparable results as well as our guidance,” said Greg L. Armstrong, Chairman and CEO of Plains All American. “This performance was underpinned by solid fee-based results in our Transportation and Facilities segments and outstanding execution in our margin-based Supply and Logistics segment.  We have increased our 2013 adjusted EBITDA guidance by $135 million, representing an approximate 7% increase over our guidance issued at the beginning of the year. This updated guidance incorporates the benefit of our strong first-quarter performance as well as a slightly improved outlook for the second quarter of 2013.

“As of the distribution payable next week, PAA will have increased year-over-year distributions by 10%. PAA ended the quarter with solid distribution coverage, a strong balance sheet, credit metrics favorable to our targets and approximately $2.8 billion in committed liquidity.

“Looking forward, PAA’s 2013 capital program and multi-billion dollar project portfolio provide visibility for continued distribution growth.  As a result of advancements in several attractive projects over the last few months, we are also increasing our 2013 capital program by $300 million to $1.4 billion.  These new projects include our recently announced Cactus pipeline that will connect our Permian Basin and Eagle Ford assets. Furthermore, we continue to make progress on a number of other projects across the US and Canada. ”

The following table summarizes selected financial information by segment for the first quarter of 2013:

Summary of Selected Financial Data by Segment(1)

(in millions)

	Three Months Ended									Three Months Ended
	March 31, 2013									March 31, 2012
	Transportation			Facilities			Supply and Logistics			Transportation		Facilities		Supply and Logistics
Reported segment profit	$	164		$	150		$	434		$	162	$	90	$	128
Selected items impacting the comparability of segment profit (2)	11			6			(27		)	11		10		69
Adjusted segment profit	$	175		$	156		$	407		$	173	$	100	$	197
Percentage change in adjusted segment profit over 2012	1		%	56		%	107		%

(1)    The Partnership’s reported results include the impact of items that affect comparability between reporting periods. The impact of these items is excluded from adjusted results. See the section of this release entitled “Non-GAAP Financial Measures and Selected Items Impacting Comparability” and the tables attached hereto for information regarding selected items that the Partnership believes impact comparability of  financial results between reporting periods.

(2)    Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

First-quarter 2013 Transportation adjusted segment profit increased 1% over comparable 2012 results.  This slight increase was primarily related to benefits from the BP NGL acquisition and increased pipeline volumes, which were largely offset by higher operating expenses related to response and remediation costs from two pipeline releases and costs incurred inspecting idled pipelines to determine if these pipelines could be placed into service.

First-quarter 2013 Facilities adjusted segment profit increased 56% over comparable 2012 results.  This increase was primarily related to capacity additions from the BP NGL and rail terminal acquisitions and recently completed organic growth projects.

First-quarter 2013 Supply and Logistics adjusted segment profit increased 107% over comparable 2012 results.  This increase was primarily related to solid execution during favorable crude oil market conditions, higher lease gathering volumes and margins and increased NGL sales volumes and margins.

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Page 3

The Partnership will hold a conference call on May 7, 2013 (see details below).  Prior to this conference call, the Partnership will furnish a current report on Form 8-K, which will include material in this news release as well as financial and operational guidance for the second quarter and full year of 2013.  A copy of the Form 8-K will be available on the Partnership’s website at  www.paalp.com, where PAA routinely posts important information about the Partnership.

Conference Call

The Partnership’s conference call will be held at 11:00 a.m. EDT on Tuesday, May 7, 2013 to discuss the following items:

1.The Partnership’s first-quarter 2013 performance;

2.The status of major expansion projects;

3.Capitalization and liquidity;

4.Financial and operating guidance for the second quarter and full year of 2013; and

5.The Partnership’s outlook for the future.

Conference Call Access Instructions

To access the Internet webcast of the conference call, please go to the Partnership’s website at www.paalp.com, choose “Investor Relations,” and then choose “Conference Calls.”  Following the live webcast, the call will be archived for a period of sixty (60) days on the Partnership’s website.

Alternatively, access to the live conference call is available by dialing toll free (800) 230-1059. International callers should dial (612) 234-9959. No password is required. The slide presentation accompanying the conference call will be available a few minutes prior to the call under the “Conference Call Summaries” portion of the “Conference Calls” tab of the “Investor Relations” section of the PAA website at www.paalp.com.

Telephonic Replay Instructions

To listen to a telephonic replay of the conference call, please dial (800) 475-6701 (or, for international callers, (320) 365-3844), and enter replay access code 285955.  The replay will be available beginning Tuesday, May 7, 2013, at approximately 1:00 p.m. EDT and will continue until 12:59 a.m. EDT on June 8, 2013.

Non-GAAP Financial Measures and Selected Items Impacting Comparability

To supplement our financial information presented in accordance with GAAP, management uses additional measures that are known as “non-GAAP financial measures” (such as adjusted EBITDA and implied distributable cash flow) in its evaluation of past performance and prospects for the future. 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 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 as “selected items impacting comparability.” We consider an understanding of these selected items impacting comparability to be material to our evaluation of our operating results and prospects.

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333 Clay Street, Suite 1600	Houston, Texas 77002	713-646-4100 / 800-564-3036

Page 4

Although we present selected items that we consider in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions and numerous other factors. These types of variations are not separately identified in this release, but will be discussed, as applicable, in management’s discussion and analysis of operating results in our Quarterly Report on Form 10-Q.

Adjusted EBITDA and other non-GAAP financial measures are reconciled to the most directly comparable GAAP measures for the periods presented in the tables attached to this release, and should be viewed in addition to, and not in lieu of, our condensed consolidated financial statements and notes thereto. In addition, the Partnership maintains on its website (www.paalp.com) a reconciliation of adjusted EBITDA and certain commonly used non-GAAP financial information to the most comparable GAAP measures. To access the information, investors should click on the “Investor Relations” link on the Partnership’s home page and then the “Non-GAAP Reconciliation” link on the Investor Relations page.

Forward Looking Statements

Except for the historical information contained herein, the matters discussed in this release are forward-looking statements that involve certain risks and uncertainties that could cause actual results to differ materially from results anticipated in the forward-looking statements. These risks and uncertainties include, among other things, 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); 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; 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 effectiveness of our risk management activities; environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves; declines in the volumes 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 or slowdown in the development of additional oil and gas reserves or other factors; shortages or cost increases of supplies, materials or labor; 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; 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; 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; interruptions in service on third-party pipelines; 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; the currency exchange rate of the Canadian dollar; weather interference with business operations or project construction; risks related to the development and operation of natural gas storage 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 discussed in the Partnership’s filings with the Securities and Exchange Commission.

Plains All American Pipeline, L.P. is a publicly traded master limited partnership engaged in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the processing, transportation, fractionation, storage and marketing of natural gas liquids. Through its general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), PAA also owns and operates natural gas storage facilities. PAA is headquartered in Houston, Texas.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2013			2012
REVENUES	$	10,620		$	9,218
COSTS AND EXPENSES
Purchases and related costs	9,437			8,502
Field operating costs	340			249
General and administrative expenses	106			94
Depreciation and amortization	82			60
Total costs and expenses	9,965			8,905
OPERATING INCOME	655			313
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities	11			7
Interest expense, net	(77		)	(65		)
Other income, net	—			2
INCOME BEFORE TAX	589			257
Current income tax expense	(46		)	(17		)
Deferred income tax expense	(7		)	(3		)
NET INCOME	536			237
Net income attributable to noncontrolling interests	(8		)	(7		)
NET INCOME ATTRIBUTABLE TO PLAINS	$	528		$	230
NET INCOME ATTRIBUTABLE TO PLAINS:
LIMITED PARTNERS	$	433		$	162
GENERAL PARTNER	$	95		$	68
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	1.28		$	0.52
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	1.27		$	0.51
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	336			314
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	339			316

ADJUSTED RESULTS:

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2013		2012
ADJUSTED NET INCOME ATTRIBUTABLE TO PLAINS	$	524	$	320
DILUTED ADJUSTED NET INCOME PER LIMITED PARTNER UNIT	$	1.26	$	0.79
ADJUSTED EBITDA	$	739	$	472

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(in millions)

	March 31,		December 31,
	2013		2012
ASSETS
Current assets	$	5,140	$	5,147
Property and equipment, net	9,883		9,643
Goodwill	2,520		2,535
Linefill and base gas	704		707
Long-term inventory	244		274
Investments in unconsolidated entities	392		343
Other, net	557		586
Total assets	$	19,440	$	19,235
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	5,022	$	5,183
Senior notes, net of unamortized discount	6,010		6,010
Long-term debt under credit facilities and other	321		310
Other long-term liabilities and deferred credits	598		586
Total liabilities	11,951		12,089
Partners’ capital excluding noncontrolling interests	6,985		6,637
Noncontrolling interests	504		509
Total partners’ capital	7,489		7,146
Total liabilities and partners’ capital	$	19,440	$	19,235

DEBT CAPITALIZATION RATIOS

(in millions)

	March 31,			December 31,
	2013			2012
Short-term debt	$	689		$	1,086
Long-term debt	6,331			6,320
Total debt	$	7,020		$	7,406
Long-term debt	$	6,331		$	6,320
Partners’ capital	7,489			7,146
Total book capitalization	$	13,820		$	13,466
Total book capitalization, including short-term debt	$	14,509		$	14,552
Long-term debt-to-total book capitalization	46		%	47		%
Total debt-to-total book capitalization, including short-term debt	48		%	51		%

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

SELECTED FINANCIAL DATA BY SEGMENT

(in millions)

	Three Months Ended									Three Months Ended
	March 31, 2013									March 31, 2012
							Supply and									Supply and
	Transportation			Facilities			Logistics			Transportation			Facilities			Logistics
Revenues (1)	$	368		$	354		$	10,225		$	317		$	236		$	8,877
Purchases and related costs (1)	(35		)	(90		)	(9,636		)	(28		)	(74		)	(8,608		)
Field operating costs (excluding equity compensation expense) (1)	(131		)	(86		)	(115		)	(98		)	(46		)	(101		)
Equity compensation expense - operations	(9		)	(1		)	(1		)	(6		)	(1		)	(1		)
Segment G&A expenses (excluding equity compensation expense) (2)	(23		)	(17		)	(26		)	(22		)	(14		)	(27		)
Equity compensation expense - general and administrative	(17		)	(10		)	(13		)	(8		)	(11		)	(12		)
Equity earnings in unconsolidated entities	11			—			—			7			—			—
Reported segment profit	$	164		$	150		$	434		$	162		$	90		$	128
Selected items impacting comparability of segment profit (3)	11			6			(27		)	11			10			69
Segment profit excluding selected items impacting comparability	$	175		$	156		$	407		$	173		$	100		$	197
Maintenance capital	$	32		$	7		$	5		$	24		$	7		$	4

(1)    Includes intersegment amounts.

(2)    Segment general and administrative expenses (G&A) 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. Includes acquisition-related expenses for the 2012 period.

(3)    Certain non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

OPERATING DATA (1)

	Three Months Ended
	March 31,
	2013	2012
Transportation activities (average daily volumes in thousands of barrels):
Crude Oil Pipelines
All American	40	25
Bakken Area Systems	123	137
Basin / Mesa	725	642
Capline	156	122
Eagle Ford Area Systems	48	10
Line 63/Line 2000	118	118
Manito	47	68
Mid-Continent Area Systems	268	221
Permian Basin Area Systems	477	454
Rainbow	122	142
Rangeland	67	64
Salt Lake City Area Systems	135	139
White Cliffs	22	18
Other	817	786
NGL Pipelines
Co-Ed	57	—
Other	207	—
Refined Products Pipelines	101	112
Tariff activities total	3,530	3,058
Trucking	111	108
Transportation activities total	3,641	3,166
Facilities activities (average monthly volumes):
Crude oil, refined products and NGL terminalling and storage (average monthly capacity in millions of barrels)	94	78
Rail unload/load volumes (average throughput in thousands of barrels per day)	216	—
Natural gas storage (average monthly capacity in billions of cubic feet)	93	76
NGL fractionation (average throughput in thousands of barrels per day)	100	11
Facilities activities total (average monthly capacity in millions of barrels) (2)	119	91
Supply and Logistics activities (average daily volumes in thousands of barrels):
Crude oil lease gathering purchases	857	798
NGL sales	284	134
Waterborne cargos	4	—
Supply and Logistics activities total	1,145	932

(1) Volumes associated with acquisitions represent total volumes (attributable to our interest) for the number of days or months we actually owned the assets divided by the number of days or months in the period.

(2) Facilities total is calculated as the sum of: (i) crude oil, refined products and NGL terminalling and storage capacity; (ii) rail load and unload volumes multipled by the number of days in the period and divided by the number of months in the period; (iii) natural gas storage 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.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

COMPUTATION OF BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2013			2012
Basic Net Income per Limited Partner Unit:
Net income attributable to Plains	$	528		$	230
Less: General partner’s incentive distribution (1)	(86		)	(65		)
Less: General partner 2% ownership (1)	(9		)	(3		)
Net income available to limited partners	433			162
Less: Undistributed earnings allocated and distributions to participating securities (1)	(3		)	—
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	430		$	162
Basic weighted average number of limited partner units outstanding	336			314
Basic net income per limited partner unit	$	1.28		$	0.52
Diluted Net Income per Limited Partner Unit:
Net income attributable to Plains	$	528		$	230
Less: General partner’s incentive distribution (1)	(86		)	(65		)
Less: General partner 2% ownership (1)	(9		)	(3		)
Net income available to limited partners	433			162
Less: Undistributed earnings allocated and distributions to participating securities (1)	(1		)	—
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	432		$	162
Basic weighted average number of limited partner units outstanding	336			314
Effect of dilutive securities: Weighted average LTIP units (2)	3			2
Diluted weighted average number of limited partner units outstanding	339			316
Diluted net income per limited partner unit	$	1.27		$	0.51

(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.

(2) Our Long-term Incentive Plan (“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.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

SELECTED ITEMS IMPACTING COMPARABILITY

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2013			2012
Selected Items Impacting Comparability - Income/(Loss) (1):
Gains/(losses) from derivative activities (2)	$	24		$	(59	)
Equity compensation expense (3)	(24		)	(26		)
Net gain on foreign currency revaluation	8			—
Tax effect on selected items impacting comparability	(5		)	—
Significant acquisition-related expenses	—			(4		)
Other (4)	1			(1		)
Selected items impacting comparability of net income attributable to Plains	$	4		$	(90	)
Impact to basic net income per limited partner unit	$	0.01		$	(0.27	)
Impact to diluted net income per limited partner unit	$	0.01		$	(0.28	)

(1) Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

(2) Includes mark-to-market gains and losses resulting from derivative instruments that are related to underlying activities in future periods.

(3) Equity compensation expense for the three months ended March 31, 2013 and 2012 excludes the portion of equity compensation expense represented by grants under LTIP that, pursuant to the terms of the grant, will be settled in cash only and have no impact on diluted units.

(4) Includes other immaterial selected items impacting comparability, as well as the noncontrolling interests’ portion of selected items.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

COMPUTATION OF ADJUSTED BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT

(in millions, except per unit data)

	Three Months Ended
	March 31,
	2013			2012
Basic Adjusted Net Income per Limited Partner Unit
Net income attributable to Plains	$	528		$	230
Selected items impacting comparability of net income attributable to Plains (1)	(4		)	90
Adjusted net income attributable to Plains	524			320
Less: General partner’s incentive distribution (2)	(86		)	(65		)
Less: General partner 2% ownership (2)	(9		)	(5		)
Adjusted net income available to limited partners	429			250
Less: Undistributed earnings allocated and distributions to participating securities (2)	(3		)	—
Adjusted limited partners’ net income	$	426		$	250
Basic weighted average number of limited partner units outstanding	336			314
Basic adjusted net income per limited partner unit	$	1.27		$	0.79
Diluted Adjusted Net Income per Limited Partner Unit
Net income attributable to Plains	$	528		$	230
Selected items impacting comparability of net income attributable to Plains (1)	(4		)	90
Adjusted net income attributable to Plains	524			320
Less: General partner’s incentive distribution (2)	(86		)	(65		)
Less: General partner 2% ownership (2)	(9		)	(5		)
Adjusted net income available to limited partners	429			250
Less: Undistributed earnings allocated and distributions to participating securities (2)	(1		)	—
Adjusted limited partners’ net income	$	428		$	250
Diluted weighted average number of limited partner units outstanding	339			316
Diluted adjusted net income per limited partner unit	$	1.26		$	0.79

(1) Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

(2) We calculate adjusted 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.

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333 Clay Street, Suite 1600	Houston, Texas 77002	713-646-4100 / 800-564-3036

Page 12

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

FINANCIAL DATA RECONCILIATIONS

(in millions)

	Three Months Ended March 31,
	2013			2012
Net Income to Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”) and Excluding Selected Items Impacting Comparability (“Adjusted EBITDA”) Reconciliations
Net Income	$	536		$	237
Add: Interest expense	77			65
Add: Income tax expense	53			20
Add: Depreciation and amortization	82			60
EBITDA	$	748		$	382
Selected items impacting comparability of EBITDA (1)	(9		)	90
Adjusted EBITDA	$	739		$	472

(1) Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability.

	Three Months Ended
	March 31,
	2013			2012
Adjusted EBITDA to Implied Distributable Cash Flow (“DCF”)
Adjusted EBITDA	$	739		$	472
Interest expense	(77		)	(65		)
Maintenance capital	(44		)	(35		)
Current income tax expense	(46		)	(17		)
Equity earnings in unconsolidated entities, net of distributions	—			(1		)
Distributions to noncontrolling interests (1)	(12		)	(12		)
Implied DCF	$	560		$	342

(1)  Includes distributions that pertain to the current period’s net income, which are paid in the subsequent period.

	Three Months Ended
	March 31,
	2013			2012
Cash Flow from Operating Activities Reconciliation
EBITDA	$	748		$	382
Current income tax expense	(46		)	(17		)
Interest expense	(77		)	(65		)
Net change in assets and liabilities, net of acquisitions	303			(22		)
Other items to reconcile to cash flows from operating activities:
Equity compensation expense	51			39
Net cash provided by operating activities	$	979		$	317

Contacts :

Roy I. Lamoreaux	Al Swanson
Director, Investor Relations	Executive Vice President, CFO
(713) 646-4222 — (800) 564-3036	(800) 564-3036

# # #
333 Clay Street, Suite 1600	Houston, Texas 77002	713-646-4100 / 800-564-3036