8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

Date of Report (Date of earliest event reported) — August 4, 2010

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

DELAWARE
(State or other jurisdiction of
incorporation) 1-14569
(Commission File Number) 76-0582150
(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:

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

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

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

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

TABLE OF CONTENTS

EX-99.1

Item 9.01.  Financial Statements and Exhibits

(d) Exhibit 99.1 — Press Release dated August 4, 2010.

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 second-quarter 2010 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 providing detailed guidance for financial performance for the third and fourth quarters of calendar 2010 and updating our previous guidance for financial performance for the full calendar year of 2010 (which supersedes guidance pertaining to 2010 contained in our Form 8-K furnished on May 5, 2010). In accordance with General Instruction B.2. of Form 8-K, the information presented herein under this 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 Third and Fourth Quarter 2010 Guidance; Update of Full Year 2010 Guidance

     EBIT and EBITDA (each as defined below in Note 1 to the “Operating and Financial Guidance” table) are non-GAAP financial measures. Net income and cash flows from operating activities are the most directly comparable GAAP measures to EBIT and EBITDA. In Note 9 below, we reconcile net income to EBIT and EBITDA for the 2010 guidance periods presented. 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 Reconciliation”), which presents a historical reconciliation of EBIT and EBITDA as well as certain other commonly used non-GAAP financial measures. We present EBIT and EBITDA because we believe they provide additional information with respect to both the performance of our fundamental business activities and our ability to meet our future debt service, capital expenditures and working capital requirements. We also believe that debt holders commonly use EBITDA to analyze partnership performance. In addition, we have highlighted the impact of our equity compensation plans, gains and losses from other derivative activities, net loss on early repayment of senior notes, and PNGS contingent consideration fair value adjustment on Segment Profit, EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

     We based our guidance for the three months ending September 30 and December 31, 2010 and twelve months ending December 31, 2010 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 LPG 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 August 3, 2010. We undertake no obligation to publicly update or revise any forward-looking statements.

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Plains All American Pipeline, L.P.
Operating and Financial Guidance
(in millions, except per unit data)

	Actual			Guidance 1
	6 Months			3 Months Ending						3 Months Ending						12 Months Ending
	Ended			September 30, 2010						December 31, 2010						December 31, 2010
	6/30/2010			Low			High			Low			High			Low			High
Segment Profit
Net revenues (including equity earnings from unconsolidated entities)	$	987		$	470		$	488		$	492		$	510		$	1,949		$	1,985
Field operating costs		(334	)		(184	)		(179	)		(175	)		(170	)		(693	)		(683	)
General and administrative expenses		(117	)		(54	)		(52	)		(54	)		(52	)		(225	)		(221	)
		536			232			257			263			288			1,031			1,081
Depreciation and amortization expense		(131	)		(63	)		(61	)		(61	)		(59	)		(255	)		(251	)
Interest expense, net		(120	)		(67	)		(65	)		(64	)		(62	)		(251	)		(247	)
Income tax expense		—			(1	)		—			(1	)		—			(2	)		—
Other income (expense), net		(1	)		(6	)		(6	)		—			—			(7	)		(7	)
Net Income	$	284		$	95		$	125		$	137		$	167		$	516		$	576
Less: Net income attributable to the noncontrolling interest		(2	)		(3	)		(3	)		(3	)		(3	)		(8	)		(8	)
Net Income attributable to Plains	$	282		$	92		$	122		$	134		$	164		$	508		$	568
Net Income to Limited Partners	$	201		$	51		$	80		$	90		$	120		$	342		$	401
Basic Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		136			136			136			136			136			136			136
Net Income Per Unit	$	1.45		$	0.36		$	0.57		$	0.65		$	0.87		$	2.47		$	2.90
Diluted Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		137			137			137			137			137			137			137
Net Income Per Unit	$	1.45		$	0.35		$	0.57		$	0.65		$	0.86		$	2.46		$	2.90
EBIT	$	404		$	163		$	190		$	202		$	229		$	769		$	823
EBITDA	$	535		$	226		$	251		$	263		$	288		$	1,024		$	1,074
Selected Items Impacting Comparability
Equity compensation charge	$	(24	)	$	(8	)	$	(8	)	$	(7	)	$	(7	)	$	(39	)	$	(39	)
Inventory Valuation Adjustments Net of Gains/(Losses) from related derivative activities		(1	)		—			—			—			—			(1	)		(1	)
Gains / (Losses) from other derivative activities		41			—			—			—			—			41			41
Net loss on early repayment of senior notes		—			(6	)		(6	)		—			—			(6	)		(6	)
PNGS contingent consideration fair value adjustment		(2	)		—			—			—			—			(2	)		(2	)
	$	14		$	(14	)	$	(14	)	$	(7	)	$	(7	)	$	(7	)	$	(7	)
Excluding Selected Items Impacting Comparability
Adjusted Segment Profit
Transportation	$	269		$	132		$	137		$	143		$	148		$	544		$	554
Facilities		134			68			72			65			69			267			275
Supply and Logistics		120			40			56			62			78			222			254
Other Income (Expense), net		(2	)		—			—			—			—			(2	)		(2	)
Adjusted EBITDA	$	521		$	240		$	265		$	270		$	295		$	1,031		$	1,081
Adjusted Net Income attributable to Plains	$	268		$	106		$	136		$	141		$	171		$	515		$	575
Adjusted Basic Net Income per Limited Partner Unit	$	1.35		$	0.46		$	0.67		$	0.70		$	0.92		$	2.51		$	2.94
Adjusted Diluted Net Income per Limited Partner Unit	$	1.34		$	0.45		$	0.67		$	0.70		$	0.91		$	2.50		$	2.93

(1) The projected average foreign exchange rate is $1.05 Canadian dollar to $1 U.S. Dollar, for the remainder of 2010. The rate as of August 3, 2010 was $1.024 Canadian dollar to $1 U.S. Dollar. A $0.10 change in the FX rate will impact forecasted EBITDA for the last six months of 2010 by approximately $7 million.

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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
Bbls/d	Barrels per day
Bcf	Billion cubic feet
LTIP	Long-Term Incentive Plan
LPG	Liquefied petroleum gas and other natural gas-related petroleum products (primarily propane and butane)
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.
Class B units	Class B units 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 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 the Butte and Frontier pipeline systems and Settoon Towing, in which we own noncontrolling 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 declines, weather and other natural disasters 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 pipeline volumes and highlights major systems that are significant either in total volumes transported or in contribution to total transportation segment profit.

	Actual					2010 Guidance
	Six Months		Three Months			Three Months			Twelve Months
	Ended		Ending			Ending			Ending
	June 30,		September 30,			December 31,			December 31,
Average Daily Volumes (000 Bbls/d)
All American		41		40			40			41
Basin		363		395			390			378
Capline		203		260			250			229
Line 63 / 2000		111		110			115			112
Salt Lake City Area Systems 1		132		140			135			135
West Texas / New Mexico Area Systems 1		376		400			385			384
Rainbow		195		185			190			191
Manito		60		60			60			60
Rangeland		51		50			50			51
Refined Products		121		120			120			120
Other		1,193		1,210			1,185			1,195
		2,846		2,970			2,920			2,896
Trucking		92		90			90			91
		2,938		3,060			3,010			2,987
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability	$	0.51	$	0.48	2	$	0.53	2	$	0.50	2

1	The aggregate of multiple systems in the respective areas.
2	Mid-point of guidance.

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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, LPG and natural gas, as well as LPG fractionation and isomerization services. We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements.
	Adjusted segment profit is forecast 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					2010 Guidance
	Six Months		Three Months			Three Months			Twelve Months
	Ended		Ending			Ending			Ending
	June 30,		September 30,			December 31,			December 31,
Operating Data
Crude oil, refined products and LPG storage (MMBbls/Mo.)		60		62			62			61
Natural Gas Storage (Bcf/Mo.)		45		50			50			48
LPG Processing (MBbl/d)		13		19			18			16
Facilities Activities Total 1
Avg. Capacity (MMBbls/Mo.)		68		71			71			69
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability	$	0.33	$	0.33	2	$	0.32	2	$	0.32	2

(1)	Calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to barrel of crude oil ratio; and (iii) LPG processing 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 activities:

• the purchase of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities, as well as the purchase of foreign cargoes at their load port and various other locations in transit;

• the storage of inventory during contango market conditions and the seasonal storage of LPG;

• the purchase of refined products and LPG from producers, refiners and other marketers;          

• the resale or exchange of crude oil, refined products and LPG at various points along the distribution chain to refiners or other resellers to maximize profits; and

• the transportation of crude oil, refined products and LPG on trucks, barges, railcars, pipelines and ocean-going vessels to our terminals and third-party terminals.

The level of profit 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 remainder of 2010 reflect the current market structure and seasonal, weather-related variations in LPG sales. The fourth quarter of 2010 reflects our expectation of normal winter weather for our LPG business. 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, production declines, 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, quality and contract structure. Accordingly, the projected segment profit per barrel can vary significantly even if aggregate volumes are in line with the forecasted levels.

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	Actual		2010 Guidance
	Six Months		Three Months			Three Months			Twelve Months
	Ended		Ending			Ending			Ending
	June 30,		September 30,			December 31,			December 31,
Average Daily Volumes (MBbl/d)
Crude Oil Lease Gathering Purchases		611		625			610			614
LPG Sales		94		72			164			106
Refined Products Sales		41		48			58			47
Waterborne foreign crude oil imported		73		70			65			70
		819		815			897			837
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability	$	0.81	$	0.60	1	$	0.95	1	$	0.78	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 during any one period due to gains and losses on intermittent sales of assets, asset retirement obligations, asset impairments or foreign exchange rates.

4.

Acquisitions and Other Capital Expenditures. Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any forecasts for acquisitions to which we may commit after the date hereof. We forecast capital expenditures during calendar 2010 to be approximately $360 million for expansion projects with an additional $85 million for maintenance capital projects. During the first six months of 2010, we spent $163 million and $33 million, respectively, for expansion and maintenance projects. Following are some of the more notable projects and forecasted expenditures for the year ending December 31, 2010:

	Calendar 2010
	(in millions)
Expansion Capital
• PAA Natural Gas Storage		95
• Patoka Phase III		18
• West Texas gathering lines		18
• Cushing — Phase VII		17
• Edmonton land purchase		16
• St. James — Phase III		15
• Cushing — Phase VIII		15
• Wichita Falls tanks		11
• Other projects (1)		155
		360
Maintenance Capital		85
Total Projected Capital Expenditures (excluding acquisitions)		445

(1) Primarily pipeline connections, upgrades and truck stations, new tank construction and refurbishing, and carry-over of projects started in 2009.

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5.	Capital Structure. This guidance is based on our capital structure as of June 30, 2010, as adjusted to give effect to the issuance on July 14, 2010 of $400 million of 3.95% 5-year senior notes as well as the anticipated redemption in September of our $175 million 6.25% senior notes due 2015.
6.	Interest Expense. Debt balances are projected based on estimated cash flows, estimated distribution rates, estimated capital expenditures for maintenance and expansion projects, 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 current forward LIBOR curve.
	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 LPG inventory and New York Mercantile Exchange and IntercontinentalExchange 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 contango-related borrowings as carrying costs of crude oil and include it in purchases and related costs.
7.	Net Income per Unit. Basic net income per limited partner unit is calculated by dividing net income allocated to limited partners by the basic weighted average units outstanding during the period.

	Actual			Guidance1
	6 Months			3 Months Ending						3 Months Ending						12 Months Ending
	Ended			September 30, 2010						December 31, 2010						December 31, 2010
	6/30/2010			Low			High			Low			High			Low			High
Numerator for basic and diluted earnings per limited partner unit:
Net Income attributable to Plains	$	282		$	92		$	122		$	134		$	164		$	508		$	568
Less: General partners incentive distribution paid (1)		(77	)		(40	)		(40	)		(42	)		(42	)		(159	)		(159	)
Subtotal		205			52			82			92			122			349			409
Less: General partner 2% ownership (1)		(4	)		(2	)		(2	)		(2	)		(2	)		(7	)		(8	)
Net income available to limited partners		201			51			80			90			120			342			401
Adjustment in accordance with application of the two-class method for MLPs (1)		(3	)		(2	)		(2	)		(1	)		(2	)		(6	)		(7	)
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	198		$	49		$	78		$	89		$	118		$	336		$	394
Denominator:
Basic weighted average number of limited partner units		136			136			136			136			136			136			136
Effect of dilutive securities:
Weighted average LTIP units		1			1			1			1			1			1			1
Diluted weighted average number of limited partner units		137			137			137			137			137			137			137
Basic net income per limited partner unit	$	1.45		$	0.36		$	0.57		$	0.65		$	0.87		$	2.47		$	2.90
Diluted net income per limited partner unit	$	1.45		$	0.35		$	0.57		$	0.65		$	0.86		$	2.46		$	2.90

⁽¹⁾ We calculate net income to our general partner based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest). However, FASB guidance requires that the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter, be utilized within the earnings per unit calculation. After adjusting for this distribution, the remaining undistributed earnings or excess distribution over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement for earnings per unit calculation purposes. We reflect the impact of the difference in (i) the distribution utilized and (ii) the calculation of the excess 2% general partner interest as the “Adjustment in accordance with application of the two-class method for MLP’s.”

In conjunction with the Pacific, Rainbow and PNGS acquisitions, our general partner reduced the amounts due it as incentive distributions by an aggregate amount of $83 million. Approximately $68.75 million of this reduction was realized as of June 30, 2010. Incentive distributions will be reduced by $7.0 million for the balance of 2010 ($3.75 million and $3.25 million, respectively, for third quarter and fourth quarter 2010) and $7.25 million in 2011.

The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. Based on the current number of units outstanding, each $0.05 per unit annual increase or decrease in the distribution relative to forecasted amounts decreases or increases net income available for limited partners by approximately $7.0 million ($0.05 per unit) on an annualized basis.

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8.	Equity Compensation Plans. The majority of grants outstanding under our equity compensation plans (LTIP and Class B units) contain vesting criteria that are based on a combination of performance benchmarks and service period. 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 August 4, 2010, estimated vesting dates range from August 2010 to May 2019 and annualized distribution levels range from $3.50 to $4.50. For some awards, a percentage of any units remaining unvested as of a date certain will vest on such date and all others will be forfeited.
	On July 13, 2010, we declared an annualized distribution of $3.77 payable on August 13, 2010 to our unitholders of record as of August 3, 2010. We have made the assessment that a $3.90 distribution level is probable of occurring and accordingly, for grants that vest at annualized distribution levels of $3.90 or less, guidance includes an accrual over the applicable service period at an assumed market price of $59.00 per unit as well as the fair value associated with awards that will vest on a date certain. The actual amount of equity compensation expense amortization 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 amount of the amortization in the early years, (iv) the probability assessment of achieving future distribution rates, and (v) new equity compensation award grants. For example, a $3.00 change in the unit price assumption at September 30, 2010 would change the third-quarter equity compensation expense by approximately $5 million. Therefore, actual net income could differ materially from our projections. Similarly, if an assessment was made that a $4.00 distribution level was probable, third-quarter equity compensation expense would increase by approximately $27 million (approximately $26 million for the cumulative effect of prior service periods and approximately $1 million for the current service period amortization).
9.	Reconciliation of Net Income to EBIT and EBITDA. The following table reconciles net income to EBIT and EBITDA, for the three-month guidance periods ending September 30 and December 31, 2010 and twelve-month guidance period ending December 31, 2010.

	Guidance
	3 Months Ending				3 Months Ending				12 Months Ending
	September 30, 2010				December 31, 2010				December 31, 2010
	Low		High		Low		High		Low		High
Reconciliation to EBITDA
Net Income	$	95	$	125	$	137	$	167	$	516	$	576
Interest expense		67		65		64		62		251		247
Income tax expense		1		—		1		—		2		—
EBIT		163		190		202		229		769		823
Depreciation and amortization		63		61		61		59		255		251
EBITDA	$	226	$	251	$	263	$	288	$	1,024	$	1,074

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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 these 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. These factors include, but are not limited to:

• failure to implement or capitalize on planned internal growth projects;

• 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;

• abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems;

• shortages or cost increases of power supplies, materials or labor;

• the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate and other factors that could cause declines in volumes shipped on our pipelines by us and third-party shippers, such as declines in production from existing oil and gas reserves or failure to develop additional oil and gas reserves;

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

• the 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 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;

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

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

• the effects of competition;

• interruptions in service and fluctuations in tariffs or volumes 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;

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• 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;

• future developments and circumstances at the time distributions are declared;

• 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, refined products and liquefied petroleum gas and other natural gas related petroleum products.

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: August 4, 2010	By:	/s/ Charles Kingswell-Smith
		Name:	Charles Kingswell-Smith
		Title:	Vice President and Treasurer

11

EX-99.1

Exhibit 99.1

Contacts:	Roy I. Lamoreaux	Al Swanson
	Director, Investor Relations	Senior Vice President, CFO
	713/646-4222 — 800/564-3036	713/646-4455 — 800/564-3036

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. Reports
Second-Quarter 2010 Results

     (Houston — August 4, 2010) Plains All American Pipeline, L.P. (NYSE: PAA) today reported net income attributable to Plains of $131 million, or $0.65 per diluted limited partner unit, for the second quarter 2010 as compared to net income attributable to Plains for the second quarter 2009 of $136 million, or $0.78 per diluted limited partner unit. The Partnership reported earnings before interest, taxes, depreciation and amortization (“EBITDA”) of $259 million for the second quarter 2010, compared with reported EBITDA of $246 million for the second quarter 2009.

     The Partnership’s reported results include the impact of items that affect comparability between reporting periods. These items are excluded from adjusted results, as further described in the table below. Accordingly, the Partnership’s second-quarter 2010 adjusted net income attributable to Plains, adjusted net income per diluted limited partner unit and adjusted EBITDA were $120 million, $0.57 and $248 million, respectively, as compared to second-quarter 2009 adjusted net income attributable to Plains, adjusted net income per diluted limited partner unit and adjusted EBITDA of $130 million, $0.74 and $240 million, respectively. (See the section of this release entitled “Non-GAAP Financial Measures” and the attached tables for discussion of EBITDA and other non-GAAP financial measures, and reconciliations of such measures to the comparable GAAP measures.)

     “Plains All American delivered second quarter results that were near the high end of our guidance range,” said Greg L. Armstrong, Chairman and CEO of Plains All American. “Strong performance from our fee based transportation and facilities segments more than offset weaker performance from our supply and logistics segment, extending our track record of delivering results in line with our quarterly guidance to 34 consecutive quarters. We continue to have strong customer demand for our assets and services and believe that we are financially and operationally well positioned to continue to deliver solid organic and acquisition oriented growth.”

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

     The following table summarizes selected items that the Partnership believes impact comparability of financial results between reporting periods (amounts in millions, except per unit amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Selected Items Impacting Comparability — Income / (Expense):
Equity compensation charge (1)	$	(9	)	$	(15	)	$	(24	)	$	(25	)
Inventory valuation adjustments net of gains/(losses) from related derivative activities (2)		(1	)		1			(1	)		24
Gains/(losses) from other derivative activities (2) (3)		22			18			41			44
PNGS contingent consideration fair value adjustment		(1	)		—			(2	)		—
Net gain on foreign currency revaluation		—			2			—			12
Selected items impacting comparability		11			6			14			55
Less: GP 2% portion of selected items impacting comparability		—			—			—			(1	)
LP 98% portion of selected items impacting comparability	$	11		$	6		$	14		$	54
Impact to basic net income per limited partner unit	$	0.08		$	0.05		$	0.10		$	0.43
Impact to diluted net income per limited partner unit	$	0.08		$	0.04		$	0.11		$	0.43

(1)	The equity compensation benefits and charges for the three and six months ended June 30, 2010 and 2009 exclude the portion of the equity compensation expense represented by grants under the LTIP Plans that, pursuant to the terms of the grant, will be settled in cash only and have no impact on diluted units. The portion of the equity compensation expense attributable to the cash portion of the LTIP Plans is approximately $4 million for each of the three month periods ended June 30, 2010 and 2009, and approximately $9 million and $5 million for the six months ended June 30, 2010 and 2009, respectively.
(2)	Gains and losses from derivative activities related to revalued inventory are included in the line item “Inventory valuation adjustments net of gains/(losses) from related derivative activities;” gains and losses from derivative activities not related to revalued inventory are included in the line item “Gains/(losses) from other derivative activities.”
(3)	Gains and losses from other derivative activities for the three-month periods ended June 30, 2010 and 2009 include gains of approximately $2 million and losses of approximately $3 million, respectively, related to interest rate derivatives, which are included in other income, net and interest expense, but do not impact segment profit. Gains and losses from other derivative activities for both the six month periods ended June 30, 2010 and 2009 include gains of approximately $3 million and losses of less than $1 million, respectively, related to interest rate derivatives, which are included in other income, net and interest expense, but do not impact segment profit.

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

     The following tables present certain selected financial information by segment for the second-quarter (amounts in millions):

	Three Months Ended									Three Months Ended
	June 30, 2010									June 30, 2009
							Supply &									Supply &
	Transportation			Facilities			Logistics			Transportation			Facilities			Logistics
Revenues (1)	$	259		$	121		$	5,901		$	238		$	85		$	4,099
Purchases and related costs (1)		(18	)		(5	)		(5,773	)		(16	)		—			(3,951	)
Field operating costs (excluding equity compensation charge) (1)		(88	)		(34	)		(49	)		(86	)		(27	)		(47	)
Equity compensation charge — operations		(2	)		—			—			(2	)		—			—
Segment G&A expenses (excluding equity compensation charge) (2)		(17	)		(9	)		(18	)		(14	)		(6	)		(17	)
Equity compensation charge — general and administrative		(5	)		(3	)		(4	)		(8	)		(3	)		(6	)
Equity earnings in unconsolidated entities		1			—			—			2			3			—
Reported segment profit	$	130		$	70		$	57		$	114		$	52		$	78
Selected items impacting comparability of segment profit:
Equity compensation charge (3)		5			2			2			8			2			5
Inventory valuation adjustments net of (gains)/losses from related derivative activities (4)		—			—			1			—			—			(1	)
(Gains)/losses from other derivative activities (4) (5)		—			—			(20	)		—			—			(21	)
Net (gain)/loss on foreign currency revaluation		—			—			—			—			—			(2	)
Subtotal		5			2			(17	)		8			2			(19	)
Segment profit excluding selected items impacting comparability	$	135		$	72		$	40		$	122		$	54		$	59
Maintenance capital	$	15		$	5		$	2		$	16		$	3		$	3

	Six Months Ended									Six Months Ended
	June 30, 2010									June 30, 2009
							Supply &									Supply &
	Transportation			Facilities			Logistics			Transportation			Facilities			Logistics
Revenues (1)	$	509		$	235		$	11,814		$	464		$	162		$	7,231
Purchases and related costs (1)		(35	)		(12	)		(11,522	)		(32	)		—			(6,854	)
Field operating costs (excluding equity compensation charge) (1)		(170	)		(68	)		(94	)		(163	)		(54	)		(96	)
Equity compensation charge — operations		(4	)		(1	)		(1	)		(4	)		—			—
Segment G&A expenses (excluding equity compensation charge) (2)		(33	)		(20	)		(37	)		(30	)		(11	)		(33	)
Equity compensation charge — general and administrative		(12	)		(5	)		(10	)		(12	)		(4	)		(10	)
Equity earnings in unconsolidated entities		2			—			—			3			5			—
Reported segment profit	$	257		$	129		$	150		$	226		$	98		$	238
Selected items impacting comparability of segment profit:
Equity compensation charge (3)		12			5			7			13			4			8
Inventory valuation adjustments net of (gains)/losses from related derivative activities (4)		—			—			1			—			—			(24	)
(Gains)/losses from other derivative activities (4)(5)		—			—			(38	)		—			—			(44	)
Net (gain)/loss on foreign currency revaluation		—			—			—			—			—			(12	)
Subtotal		12			5			(30	)		13			4			(72	)
Segment profit excluding selected items impacting comparability	$	269		$	134		$	120		$	239		$	102		$	166
Maintenance capital	$	22		$	8		$	3		$	30		$	9		$	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 based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.
(3)	The equity compensation benefits and charges for the three and six months ended June 30, 2010 and 2009 exclude the portion of the equity compensation expense represented by grants under the LTIP Plans that, pursuant to the terms of the grant, will be settled in cash only and have no impact on diluted units. The portion of the equity compensation expense attributable to the cash portion of the LTIP Plans is approximately $4 million for each of the three month periods ended June 30, 2010 and 2009, and approximately $9 million and $5 million for the six months ended June 30, 2010 and 2009, respectively.
(4)	Gains and losses from derivative activities related to revalued inventory are included in the line item “Inventory valuation adjustments net of (gains)/losses from related derivative activities;” gains and losses from derivative activities not related to revalued inventory are included in the line item “(Gains)/losses from other derivative activities.”
(5)	Gains and losses from other derivative activities for the three-month periods ended June 30, 2010 and 2009 include gains of approximately $2 million and losses of approximately $3 million, respectively, related to interest rate derivatives, which are included in other income, net and interest expense, but do not impact segment profit. Gains and losses from other derivative activities for both the six month periods ended June 30, 2010 and 2009 include gains of approximately $3 million and losses of less than $1 million, respectively, related to interest rate derivatives, which are included in other income, net and interest expense, but do not impact segment profit.

     Adjusted segment profit for the Transportation segment for the second quarter of 2010 increased 11% over comparable 2009 results, primarily due to higher average tariffs and favorable foreign exchange rates partially offset by lower pipeline loss allowance revenue.

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

     Adjusted segment profit for the Facilities segment for the second quarter of 2010 increased 33% over comparable 2009 results, primarily due to acquisition and organic growth capacity additions.

     Adjusted segment profit for the Supply and Logistics segment for the second quarter of 2010 decreased 32% when compared to second quarter 2009 results. This decrease reflects lower LPG margins and less favorable crude oil grade differentials in the second quarter 2010 combined with contango-market-related overperformance in the second quarter 2009.

     The Partnership’s basic weighted average units outstanding for the second quarter of 2010 totaled 136 million (137 million diluted) as compared to 129 million (130 million diluted) in last year’s second quarter. On June 30, 2010, the Partnership had approximately 136.4 million units outstanding, long-term debt of approximately $4.4 billion ($500 million of which supports hedged inventory) and an adjusted long-term debt-to-total capitalization ratio of 47%.

     The Partnership has declared a quarterly distribution of $0.9425 per unit ($3.77 per unit on an annualized basis) payable August 13, 2010 on its outstanding limited partner units. This distribution represents an increase of approximately 4.1% over the quarterly distribution paid in August 2009 and an increase of approximately 0.8% from the May 2010 distribution level.

     Prior to its August 5^th conference call, the Partnership will furnish a current report on Form 8-K, which will include material in this press release and financial and operational guidance for the third quarter and full year 2010. A copy of the Form 8-K will be available on the Partnership’s website at www.paalp.com.

Non-GAAP Financial Measures

     In this release, the Partnership’s EBITDA disclosure is not presented in accordance with generally accepted accounting principles and is not intended to be used in lieu of GAAP presentations of net income or cash flows from operating activities. EBITDA is presented because we believe it provides additional information with respect to both the performance of our fundamental business activities as well as our ability to meet our future debt service, capital expenditures and working capital requirements. We also believe that debt holders commonly use EBITDA to analyze Partnership performance. In addition, we present selected items that impact the comparability of our operating results as additional information that may be helpful to your understanding of our financial results. We consider an understanding of these selected items impacting comparability to be material to our evaluation of our operating results and prospects. 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.

     A reconciliation of net income to EBITDA and EBITDA to cash flows from operating activities for the

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

periods presented is included in the tables attached to this release. In addition, the Partnership maintains on its website (www.paalp.com) a reconciliation of all non-GAAP financial information, such as EBITDA, 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.

Conference Call

     The Partnership will host a conference call at 11:00 AM (Eastern) on Thursday, August 5, 2010 to discuss the following items:

1.	The Partnership’s second-quarter 2010 performance;
2.	The status of major expansion projects;
3.	Capitalization and liquidity;
4.	Financial and operating guidance for the third quarter and full year 2010; and
5.	The Partnership’s outlook for the future.

Webcast Instructions

     To access the Internet webcast, 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.

     If you are unable to participate in the webcast, you may access the live conference call by dialing toll free 800-230-1096. International callers should dial 612-332-0228. No password is required. You may access the slide presentation accompanying the conference call a few minutes prior to the call under the Conference Call Summaries portion of the Conference Calls tab of the Investor Relations section of PAA’s 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 replay access code 163557. The replay will be available beginning Thursday, August 5, 2010, at approximately 12:00 PM (Central) and continue until 11:59 PM (Central) Sunday, September 5, 2010.

     Plains All American Pipeline, L.P. is a publicly-traded master limited partnership engaged in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas related petroleum products. Through its general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), PAA is also engaged in the development and operation of natural gas storage facilities. PAA is headquartered in Houston, TX.

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

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

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 on planned internal growth projects; 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; abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems; shortages or cost increases of power supplies, materials or labor; the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate and other factors that could cause declines in volumes shipped on our pipelines by us and third-party shippers, such as declines in production from existing oil and gas reserves or failure to develop additional oil and gas reserves; fluctuations in refinery capacity in areas supplied by our mainlines and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transportation throughput requirements; the 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 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; unanticipated changes in crude oil market structure and volatility (or lack thereof); the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations; the effects of competition; interruptions in service and fluctuations in tariffs or volumes 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; future developments and circumstances at the time distributions are declared; 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, refined products and liquefied petroleum gas and other natural gas related petroleum products discussed in the Partnership’s filings with the Securities and Exchange Commission.

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
REVENUES	$	6,124		$	4,282		$	12,248		$	7,585
COSTS AND EXPENSES
Purchases and related costs		5,641			3,829			11,263			6,619
Field operating costs		171			160			334			312
General and administrative expenses		56			54			117			100
Depreciation and amortization		64			56			131			114
Total costs and expenses		5,932			4,099			11,845			7,145
OPERATING INCOME		192			183			403			440
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		1			5			2			8
Interest expense		(62	)		(56	)		(120	)		(107	)
Other income, net		2			2			(1	)		5
INCOME BEFORE TAX		133			134			284			346
Current income tax (expense)/benefit		1			—			(1	)		(2	)
Deferred income tax (expense)/benefit		(1	)		2			1			3
NET INCOME		133			136			284			347
Less: Net income attributable to noncontrolling interests		(2	)		—			(2	)		—
NET INCOME ATTRIBUTABLE TO PLAINS	$	131		$	136		$	282		$	347
NET INCOME:
LIMITED PARTNERS	$	90		$	102		$	201		$	282
GENERAL PARTNER	$	41		$	34		$	81		$	65
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.65		$	0.79		$	1.45		$	2.20
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.65		$	0.78		$	1.45		$	2.18
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING		136			129			136			126
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING		137			130			137			127

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
OPERATING DATA(1)
Transportation activities (Average Daily Volumes, thousands of barrels):
Tariff activities
All American		43		42		41		39
Basin		369		440		363		417
Capline		246		204		203		205
Line 63/Line 2000		112		145		111		133
Salt Lake City Area Systems (2)		136		139		132		121
West Texas/New Mexico Area Systems (2)		387		374		376		384
Manito		60		61		60		63
Rainbow		198		181		195		188
Rangeland		54		53		51		56
Refined products		126		91		121		94
Other		1,256		1,260		1,193		1,201
Tariff activities total		2,987		2,990		2,846		2,901
Trucking		95		84		92		86
Transportation activities total		3,082		3,074		2,938		2,987
Facilities activities (Average Monthly Volumes):
Crude oil, refined products, and LPG storage (average monthly capacity in millions of barrels)		61		56		60		55
Natural gas storage (average monthly capacity in billions of cubic feet)		49		20		45		18
LPG processing (average throughput in thousands of barrels per day)		14		17		13		16
Facilities activities total (average monthly capacity in millions of barrels) (3)		70		60		68		59
Supply & Logistics activities (Average Daily Volumes, thousands of barrels):
Crude oil lease gathering purchases		620		623		611		627
LPG sales		54		60		94		102
Waterborne foreign crude oil imported		74		57		73		57
Refined products		42		36		41		36
Supply & Logistics activities total		790		776		819		822

(1)	Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.
(2)	The aggregate of multiple systems in the respective areas.
(3)	Facilities total is calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to crude oil barrel ratio; and (iii) LPG processing volumes multiplied by the number of days in the period and divided by the number of months in the period.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATED BALANCE SHEET DATA
(In millions)

	June 30,		December 31,
	2010		2009
ASSETS
Current assets	$	3,498	$	3,658
Property and equipment, net		6,410		6,340
Linefill and base gas		504		501
Long-term inventory		118		121
Goodwill		1,285		1,287
Other long-term assets, net		553		451
Total assets	$	12,368	$	12,358
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	3,377	$	3,782
Long-term debt under credit facilities and other		213		6
Senior notes, net of unamortized discount		4,137		4,136
Other long-term liabilities and net deferred credits		226		275
Total liabilities		7,953		8,199
Partners’ capital excluding noncontrolling interests		4,184		4,096
Noncontrolling interests		231		63
Total partners’ capital		4,415		4,159
Total liabilities and partners’ capital	$	12,368	$	12,358

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

CREDIT RATIOS
(In millions)

							June 30,
	June 30,						2010
	2010			Adjustment(1)			Adjusted
Short-term debt	$	1,025		$	500		$	1,525
Long-term debt		4,350			(500	)		3,850
Total debt	$	5,375		$	—		$	5,375
Long-term debt		4,350			(500	)		3,850
Partners’ capital		4,415			—			4,415
Total book capitalization	$	8,765		$	(500	)	$	8,265
Total book capitalization including short-term debt	$	9,790		$	—		$	9,790
Long-term debt to total book capitalization		50	%					47	%
Total debt to total book capitalization including short-term debt		55	%					55	%

(1) The adjustment represents the portion of the 4.25% senior notes due September 2012 that has been used to fund hedged inventory and would be classified as short-term debt if funded on our credit facilities. These notes were issued in July 2009 and the proceeds are being used to supplement capital available from our hedged inventory facility.

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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Numerator for basic and diluted earnings per limited partner unit:
Net Income Attributable to Plains	$	131		$	136		$	282		$	347
Less: General partner’s incentive distribution paid (1)		(39	)		(32	)		(77	)		(60	)
Subtotal		92			104			205			287
Less: General partner 2% ownership (1)		(2	)		(2	)		(4	)		(5	)
Net income available to limited partners		90			102			201			282
Adjustment in accordance with application of the two-class method for MLPs (1)		(1	)		—			(3	)		(5	)
Net income available to limited partners in accordance with application of the two-class method for MLPs (1)	$	89		$	102		$	198		$	277
Denominator:
Basic weighted average number of limited partner units outstanding		136			129			136			126
Effect of dilutive securities:
Weighted average LTIP units		1			1			1			1
Diluted weighted average number of limited partner units outstanding		137			130			137			127
Basic net income per limited partner unit	$	0.65		$	0.79		$	1.45		$	2.20
Diluted net income per limited partner unit	$	0.65		$	0.78		$	1.45		$	2.18

(1) We calculate net income available to limited partners based on the distribution paid during the current quarter (including the incentive distribution interest in excess of the 2% general partner interest). However, FASB guidance requires that the distribution pertaining to the current period’s net income, which is to be paid in the subsequent quarter, be utilized in the earnings per unit calculation. After adjusting for this distribution, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement for earnings per unit calculation purposes. We reflect the impact of the difference in (i) the distribution utilized and (ii) the calculation of the excess 2% general partner interest as the “Adjustment in accordance with application of the two-class method for MLPs.”

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

FINANCIAL DATA RECONCILIATIONS
(In millions)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Net income to earnings before interest, taxes, depreciation and amortization (“EBITDA”) and excluding selected items impacting comparability (“Adjusted EBITDA”) reconciliations
Net Income	$	133		$	136		$	284		$	347
Add: Interest expense		62			56			120			107
Add: Income tax expense		—			(2	)		—			(1	)
Add: Depreciation and amortization		64			56			131			114
EBITDA		259			246			535			567
Selected items impacting comparability		(11	)		(6	)		(14	)		(55	)
Adjusted EBITDA	$	248		$	240		$	521		$	512

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Adjusted EBITDA to Distributable Cash Flow (“DCF”)
Adjusted EBITDA	$	248		$	240		$	521		$	512
Interest expense		(62	)		(56	)		(120	)		(107	)
Maintenance capital		(22	)		(22	)		(33	)		(43	)
Current income tax (expense)/benefit		1			—			(1	)		(2	)
Equity earnings in unconsolidated entities, net of distributions		—			(2	)		1			(3	)
Distribution to noncontrolling interests (1)		(4	)		—			(5	)		—
DCF	$	161		$	160		$	363		$	357

(1) Includes distributions that are declared in the current quarter and are to be paid in the subsequent quarter.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Cash flow from operating activities reconciliation
EBITDA	$	259		$	246		$	535		$	567
Current income tax (expense)/benefit		1			—			(1	)		(2	)
Interest expense		(62	)		(56	)		(120	)		(107	)
Net change in assets and liabilities, net of acquisitions		(319	)		(400	)		(164	)		(201	)
Other items to reconcile to cash flows from operating activities:
Equity compensation charge		14			19			33			30
Net cash provided by/(used in) operating activities	$	(107	)	$	(191	)	$	283		$	287

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)

FINANCIAL DATA RECONCILIATIONS
(In millions, except per unit data) (continued)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Net income and earnings per limited partner unit excluding selected items impacting comparability
Net Income Attributable to Plains	$	131		$	136		$	282		$	347
Selected items impacting comparability		(11	)		(6	)		(14	)		(55	)
Adjusted Net Income Attributable to Plains	$	120		$	130		$	268		$	292
Net income available to limited partners in accordance with application of the two-class method for MLPs	$	89		$	102		$	198		$	277
Limited partners’ 98% of selected items impacting comparability		(11	)		(6	)		(14	)		(54	)
Adjusted limited partners’ net income	$	78		$	96		$	184		$	223
Adjusted basic net income per limited partner unit	$	0.57		$	0.74		$	1.35		$	1.77
Adjusted diluted net income per limited partner unit	$	0.57		$	0.74		$	1.34		$	1.75
Basic weighted average units outstanding		136			129			136			126
Diluted weighted average units outstanding		137			130			137			127