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 6, 2007

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:

     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

Press Release

TABLE OF CONTENTS

Item 9.01. Financial Statements and Exhibits

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

SIGNATURES

Exhibit Index

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Item 9.01. Financial Statements and Exhibits

     (d) Exhibit 99.1—Press release dated August 6, 2007

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 2007 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 quarter of calendar 2007 and modifying certain aspects of our previous guidance for financial performance for the full calendar year 2007 (which supersedes guidance in our Form 8-K furnished on May 2, 2007 and press release dated May 29, 2007). 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, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.

Disclosure of Third and Fourth Quarter 2007 Guidance; Update of Full Year 2007 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 10 below, we reconcile EBITDA and EBIT to net income for the 2007 guidance periods presented. It is, however, impractical to reconcile EBIT and EBITDA to cash flows from operating activities for forecasted periods. 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 certain commonly used non-GAAP financial measures, including EBIT and EBITDA. 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 long-term incentive plan, and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments) on Segment Profit, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

     The following guidance for the three-month periods ending September 30 and December 31, 2007 and the twelve-month period ending December 31, 2007 is based on assumptions and estimates that we believe are reasonable given our assessment of historical trends, business cycles and other information reasonably available. Our assumptions and future performance are both, however, 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 the 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 6, 2007. 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*
	Six Months			Three Months Ending						Three Months Ending						Twelve Months Ending
	Ended			September 30, 2007						December 31, 2007						December 31, 2007
	June 30, 2007			Low			High			Low			High			Low			High
Segment Profit
Net revenues (including equity in earnings )	$	726.7		$	339.5		$	357.0		$	329.5		$	347.0		$	1,395.7		$	1,430.7
Field operating costs		(261.4	)		(136.0	)		(134.0	)		(130.0	)		(128.0	)		(527.4	)		(523.4	)
General and administrative expenses		(94.5	)		(36.5	)		(36.0	)		(37.5	)		(37.0	)		(168.5	)		(167.5	)
		370.8			167.0			187.0			162.0			182.0			699.8			739.8
Depreciation and amortization expense		(92.0	)		(48.0	)		(46.0	)		(49.0	)		(47.0	)		(189.0	)		(185.0	)
Interest expense, net		(82.3	)		(40.0	)		(38.0	)		(42.0	)		(40.0	)		(164.3	)		(160.3	)
Income tax expense		(12.2	)		(1.7	)		(1.5	)		(1.7	)		(1.5	)		(15.6	)		(15.2	)
Other income (expense), net		5.2			—			—			—			—			5.2			5.2
Net Income	$	189.5		$	77.3		$	101.5		$	69.3		$	93.5		$	336.1		$	384.5
Net Income to Limited Partners	$	154.4		$	56.2		$	79.9		$	48.4		$	72.1		$	259.0		$	306.4
Basic Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		109.9			116.0			116.0			116.0			116.0			113.1			113.1
Net Income Per Unit	$	1.40		$	0.48		$	0.69		$	0.42		$	0.62		$	2.30		$	2.71
Diluted Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		110.9			116.8			116.8			116.9			116.9			114.1			114.1
Net Income Per Unit	$	1.39		$	0.48		$	0.68		$	0.41		$	0.62		$	2.28		$	2.69
EBIT	$	284.0		$	119.0		$	141.0		$	113.0		$	135.0		$	516.0		$	560.0
EBITDA	$	376.0		$	167.0		$	187.0		$	162.0		$	182.0		$	705.0		$	745.0
Selected Items Impacting Comparability
LTIP charge	$	(37.4	)	$	(8.0	)	$	(8.0	)	$	(8.0	)	$	(8.0	)	$	(53.4	)	$	(53.4	)
Deferred Income Tax Expense**		(10.8	)		—			—			—			—			(10.8	)		(10.8	)
SFAS 133 Mark-to-Market Adjustment		(2.1	)		—			—			—			—			(2.1	)		(2.1	)
	$	(50.3	)	$	(8.0	)	$	(8.0	)	$	(8.0	)	$	(8.0	)	$	(66.3	)	$	(66.3	)
Excluding Selected Items Impacting Comparability
Adjusted Segment Profit
Transportation	$	171.7		$	88.0		$	93.0		$	89.0		$	94.0		$	348.7		$	358.7
Facilities		55.7			25.0			29.0			28.0			31.0			108.7			115.7
Marketing		182.6			62.0			73.0			53.0			65.0			297.6			320.6
Other income (expense), net		5.5			—			—			—			—			5.5			5.5
Adjusted EBITDA***	$	415.5		$	175.0		$	195.0		$	170.0		$	190.0		$	760.5		$	800.5
Adjusted Net Income	$	239.8		$	85.3		$	109.5		$	77.3		$	101.5		$	402.4		$	450.8
Adjusted Basic Net Income per Limited Partner Unit	$	1.85		$	0.55		$	0.76		$	0.48		$	0.69		$	2.88		$	3.30
Adjusted Diluted Net Income per Limited Partner Unit	$	1.84		$	0.55		$	0.75		$	0.48		$	0.68		$	2.87		$	3.27

*	The projected average foreign exchange rate is $1.07 CAD to $1 USD. The rate as of August 3, 2007 was $1.05 CAD to $1 USD.
**	Amount related to Canadian tax legislation.
***	Excludes deferred income tax expenses included in the list of selected items impacting comparability.

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Notes and Significant Assumptions:

1. Definitions.

Bcf	Billion cubic feet
EBIT	Earnings before interest and taxes
EBITDA	Earnings before interest, taxes and depreciation and amortization expense
Bbls/d	Barrels per day
Segment Profit	Net revenues (including equity earnings, as applicable) less purchases, field operating costs, and segment general and administrative expenses
LTIP	Long-Term Incentive Plan
LPG	Liquefied petroleum gas and other petroleum products
FX	Foreign currency exchange

2. Business Segments. We manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing. 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, trucks and gathering systems. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity and transportation fees. We also include in this segment our equity earnings from our investments in the Butte and Frontier pipeline systems, in which we own minority interests, and Settoon Towing, in which we own a 50% interest.
	Pipeline volume estimates are based on historical trends, anticipated future operating performance and completion of internal growth projects. Volumes are influenced by temporary market-driven storage and withdrawal of oil, maintenance schedules at refineries, production declines and other external factors beyond our control. Segment profit is forecast 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 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.

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	Calendar 2007
	Actual		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		48		47			48			48
Basin		374		400			375			379
Capline		233		225			225			229
Line 63 / Line 2000		181		180			180			183
Salt Lake City		63		63			63			63
N. Dakota / Trenton		96		100			100			98
West Texas / New Mexico 1		381		385			380			381
Manito		74		75			75			75
Refined Products		110		110			110			110
Other		1,131		1,110			1,154			1,129
		2,691		2,695			2,710			2,695
Trucking		108		110			115			111
		2,799		2,805			2,825			2,806
Average Segment Profit ($/Bbl)
Excluding Selected Items Impacting Comparability	$	0.34	$	0.35	(2)	$	0.35	(2)	$	0.35	(2)

1	The aggregate of multiple systems in the West Texas / New Mexico area.
2	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 and LPG, 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. This segment also includes our equity earnings from our 50% investment in PAA/Vulcan Gas Storage, LLC which owns and operates approximately 25.7 billion cubic feet of underground natural gas storage capacity and is constructing an additional 24 Bcf of underground storage capacity.

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.

	Calendar 2007
	Actual		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.)		35.6		37.0			39.0			36.9
Natural Gas Storage (Bcf/Mo.)		12.9		12.9			12.9			12.9
LPG Processing (MBbl/d)		16.9		17.0			17.0			17.0
Facilities Activities Total 1
Avg. Capacity (MMBbls/Mo.)		38.3		39.7			41.7			39.6
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability	$	0.24	$	0.23	2	$	0.24	2	$	0.24	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 crude oil barrel ratio; and (iii) LPG processing volumes multiplied by the number of days in the month and divided by 1,000 to convert to monthly volumes in millions.

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(2) Mid-point of guidance.

C. Marketing. Our marketing segment operations generally consist of the following merchant 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;

• storage of inventory during contango market conditions;

• 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; and

• arranging for 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 marketing 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 September 30 reflect a moderately strong market, whereas forecasted operating results for the three-month period ending December 31, 2007 reflect a weaker, less volatile market than experienced in the first nine months of 2007. Unexpected changes in market structure or volatility (or lack thereof) could cause actual results to differ materially from forecasted results.

We forecast segment profit using the volume assumptions stated below and estimates of unit margins, field operating costs, G&A expenses and carrying costs for contango inventory based on current and anticipated market conditions. 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.

	Calendar 2007
	Actual		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		694		705			705			701
LPG Sales		89		65			105			87
Refined Products		8		15			15			17
Waterborne Foreign Crude Imported		72		75			75			74
		863		860			900			873
Segment Profit per Barrel ($/Bbl)
Excluding Selected Items Impacting Comparability	$	1.17	$	0.85	1	$	0.71	1	$	0.97	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 is computed using the straight-line method over estimated useful lives, which range from 3 years (for office furniture and equipment) to 40 years (for certain pipelines, crude oil terminals and facilities) and includes gains and losses on the sale of assets.

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4.

Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). The guidance presented above does not include forecasts with respect to potential gains or losses related to derivatives accounted for under SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to these derivatives (primarily mark-to-market adjustments) could cause actual net income to differ materially from our projections.

5.

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 any acquisition that may be made after the date hereof. Capital expenditures for expansion projects are forecasted to be approximately $550 million during calendar 2007, of which $257 was incurred in the first six months. Following are some of the more notable projects and forecasted expenditures for the year:

	Calendar 2007
	(in millions)
Expansion Capital
• St. James, Louisiana Storage Facility	$	75
• Cheyenne Pipeline		58
• Salt Lake City Expansion		52
• Cushing Tankage — Phase VI		34
• Patoka Tankage		32
• Martinez Terminal		25
• Fort Laramie Tank Expansion		21
• High Prairie Rail Terminal		13
• Paulsboro Expansion		12
• Elk City to Calumet		12
• Pier 400		10
• Kerrobert Tankage		10
• Other Projects		196
		550
Maintenance Capital		52
Total Projected Capital Expenditures (excluding acquisitions)	$	602

	Capital expenditures for maintenance projects are forecast to be approximately $52 million during 2007, of which $22 million was incurred in the first six months.
6.	Capital Structure. This guidance is based on our capital structure as of June 30, 2007. The Partnership’s policy is to finance acquisitions and major growth capital projects with at least 50% equity or cash flow in excess of distributions. As a result of our recent equity financing activities in combination with our projected 2007 cash flows in excess of distributions, we have pre-funded the required equity financing associated with our 2007 expansion capital program but will continue to monitor the potential need for additional equity necessary to maintain credit metrics consistent with our targeted credit ratings should inventory requirements associated with our continuing expansion of merchant activities in crude oil, LPG and refined products increase meaningfully.
7.	Interest Expense. Debt balances are projected based on estimated cash flows, current distribution rates, forecasted 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.
	Annual 2007 interest expense is expected to be between $160 million and $164 million, assuming an average long-term debt balance of approximately $2.6 billion during the period. 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 contango inventory. We treat interest on contango related borrowings as carrying costs of crude oil and include it as part of the purchase price of crude oil.
8.	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.

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	Actual									Guidance (in millions)
	6 Mo.			Three Months Ending						Three Months Ending						Twelve Months Ending
	Ended			September 30, 2007						December 31, 2007						December 31, 2007
	06/30/07			Low			High			Low			High			Low			High
Numerator for basic and diluted earnings per limited partner unit:
Net Income	$	189.5		$	77.3		$	101.5		$	69.3		$	93.5		$	336.1		$	384.5
General partners incentive distribution		(42.0	)		(25.0	)		(25.0	)		(25.0	)		(25.0	)		(92.0	)		(92.0	)
General partners incentive distribution reduction		10.0			5.0			5.0			5.0			5.0			20.0			20.0
		157.5			57.3			81.5			49.3			73.5			264.1			312.5
General partner 2% ownership		(3.1	)		(1.1	)		(1.6	)		(1.0	)		(1.5	)		(5.3	)		(9.6	)
Net income available to limited partners	$	154.4		$	56.2		$	79.9		$	48.4		$	72.1		$	258.9		$	306.3
Denominator:
Denominator for basic earnings per limited partner unit- weighted average number of limited partner units		109.9			116.0			116.0			116.0			116.0			113.1			113.1
Effect of dilutive securities:
Weighted average LTIP units		1.0			0.8			0.8			0.9			0.9			0.9			0.9
Denominator for diluted earnings per limited partner unit- weighted average number of limited partner units		110.9			116.8			116.8			116.9			116.9			114.1			114.1
Basic net income per limited partner unit	$	1.40		$	0.48		$	0.69		$	0.42		$	0.62		$	2.29		$	2.71
Diluted net income per limited partner unit	$	1.39		$	0.48		$	0.68		$	0.41		$	0.62		$	2.27		$	2.69

	Net income allocated to limited partners is impacted by the income allocated to the general partner and the amount of the incentive distribution paid to the general partner. The amount of income allocated to our limited partner interests is 98% of the total partnership income after deducting the amount of the general partner’s incentive distribution. Based on our current annualized distribution rate of $3.32 per unit, our general partner’s distribution is forecast to be approximately $107.7 million annually, of which $99.8 million is attributed to the incentive distribution rights. However, in conjunction with the Pacific acquisition, the general partner agreed to reduce the amounts due it as incentive distributions. The reduction will be effective for five years, as follows: (i) $5 million per quarter for the first four quarters beginning with the February 2007 distribution, (ii) $3.75 million per quarter for the following eight quarters, (iii) $2.5 million per quarter for the following four quarters, and (iv) $1.25 million per quarter for the final four quarters. The total reduction in incentive distributions will be $65 million. Total incentive distributions to the general partner in 2007 will be reduced by $20.0 million. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. Each $0.05 per unit annual increase in the distribution over $3.32 per unit decreases net income available for limited partners by approximately $5.8 million ($0.05 per unit) on an annualized basis.
9.	Long-term Incentive Plans. The majority of grants outstanding under our Long-Term Incentive Plans 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 earliest vesting dates and the dates on which minimum distribution levels are reached. Among the various grants, vesting dates range from May 2008 to May 2012 and minimum annualized distribution levels range from $2.80 to $4.00. For some awards, a percentage of any remaining units will vest on a date certain in 2011 or 2012.
	In addition to achieving the distribution level of $3.32, we have deemed probable that the $3.50 distribution level will be achieved. Accordingly, for grants that vest at annualized distribution levels of $3.50 or less, guidance includes an accrual over the corresponding service period at an assumed market price of $64.00 per unit as well as the fair value associated with awards that will vest on a date certain. For 2007, the guidance includes approximately $56.2 million of expense associated with these grants. The actual amount of LTIP expense amortization in any given year will be directly influenced by (i) our unit price at the end of each reporting period, (ii) our unit price on the date of actual vesting, (iii) the amount of amortization in the early years, and (iv) new LTIP award grants. For example, a $3.00 change in the unit price assumption at September 30, 2007 would change the total amortization by $2.6 million — $0.3 million for the current quarter and $2.3 million for the life-to-date adjustment to the liability accrued in prior periods. Therefore, actual net income could differ materially from our projections.
	The amount of LTIP expense highlighted in selected items impacting comparability excludes the portion of the LTIP expense represented by LTIP grants under the 2006 Plan that, pursuant to the terms of the Plan, will be settled in cash only ($2.8 million) and have no impact in the determination of diluted units.

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10. Reconciliation of EBITDA and EBIT to Net Income. The following table reconciles the 2007 guidance ranges for EBITDA and EBIT to net income.

	Three Months Ending				Three Months Ending				Twelve Months Ending
	September 30, 2007				December 31, 2007				December 31, 2007
	Low		High		Low		High		Low		High
Reconciliation to Net Income
EBITDA	$	167.0	$	187.0	$	162.0	$	182.0	$	705.0	$	745.0
Depreciation and amortization		48.0		46.0		49.0		47.0		189.0		185.0
EBIT		119.0		141.0		113.0		135.0		516.0		560.0
Interest expense		40.0		38.0		42.0		40.0		164.3		160.3
Income tax expense		1.7		1.5		1.7		1.5		15.6		15.2
Net Income	$	77.3	$	101.5	$	69.3	$	93.5	$	336.1	$	384.5

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 identified by the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast” and similar expressions and statements regarding our business strategy, plans and objectives of our management 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 are 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:

• the failure to realize the anticipated synergies and other benefits of the merger with Pacific;

• the success of our risk management activities;

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

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

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

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

• 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;

• 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 transmission throughput requirements;

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

• our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;

• 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;

10

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

• the impact of current and future laws, rulings and governmental regulations;

• the effects of competition;

• continued creditworthiness of, and performance by, our counterparties;

• 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;

• general economic, market or business conditions; 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.

11

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: PLAINS AAP, L. P., its general partner
	By: PLAINS ALL AMERICAN GP LLC, its general partner
Date: August 6, 2007	By:	/s/ PHIL KRAMER
	Name:	Phil Kramer
	Title:	Executive Vice President and Chief Financial Officer

12

Exhibit Index

Exhibit 99.1—Press release dated August 6, 2007

13

EX-99.1

Exhibit 99.1

Contacts: Phil D. Kramer
Executive Vice President and CFO
713/646-4560 — 800/564-3036 Roy I. Lamoreaux
Manager, Investor Relations
713/646-4222 — 800/564-3036

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P.
Reports Strong Second Quarter 2007 Results —
Net Income Increases 31%; EBITDA Increases 76%

(Houston — August 6, 2007) Plains All American Pipeline, L.P. (NYSE: PAA) today reported second-quarter 2007 net income of $104.8 million, or $0.78 per diluted limited partner unit, compared to net income for the second quarter of 2006 of $80.3 million and $0.81 per diluted limited partner unit. These second quarter 2007 results represent an increase of 31% and a decrease of 4%, respectively, compared to second quarter 2006 results. The Partnership’s basic weighted average units outstanding for the second quarter of 2007 totaled 110.5 million (111.2 million diluted) compared to 77.0 million (77.8 million diluted) for the second quarter 2006.

The Partnership reported earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the second quarter of 2007 of $210.2 million, an increase of 76% compared with EBITDA of $119.6 million for the second quarter of 2006. (See the section of this release entitled “Non-GAAP Financial Measures” and the attached tables for a discussion of EBITDA and other non-GAAP financial measures, and reconciliations of such measures to the comparable GAAP measures.)

“The second quarter’s strong results reflect solid contributions from each of our business segments and underscore the ability of our assets and our business model to generate performance above our baseline guidance in favorable market conditions,” stated Greg L. Armstrong, Chairman and CEO of Plains All American. “Based on these results, our second-half guidance, our recent distribution increase and our other activities, we believe we are well positioned to achieve the goals we set for 2007.”

Reported results include the impact of various items that affect comparability between reporting periods. Adjusted results exclude selected items impacting comparability, as further described in the table below. After excluding such items, the Partnership’s second-quarter 2007 adjusted net income, adjusted EBITDA and adjusted net income per diluted limited partner unit were $120.2 million, $214.8 million and $0.91, respectively. Comparable results for the second quarter 2006 were $88.9 million, $128.2 million and $1.03, respectively.

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The following table summarizes selected items that the Partnership believes impact comparability of financial results between reporting periods:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(In millions, except per unit data)
Selected items impacting comparability
LTIP charge(1)	$	(19.5	)	$	(6.2	)	$	(37.4	)	$	(16.8	)
Cumulative effect of change in accounting principle — LTIP(2)		—			—			—			6.3
SFAS 133 mark-to-market adjustment(3)		14.9			(2.4	)		(2.1	)		(3.1	)
Deferred income tax expense(4)		(10.8	)		—			(10.8	)		—
Selected items impacting comparability		(15.4	)		(8.6	)		(50.3	)		(13.6	)
Less: GP 2% portion of selected items impacting comparability		0.3			0.2			1.0			0.3
LP 98% portion of selected items impacting comparability	$	(15.1	)	$	(8.4	)	$	(49.3	)	$	(13.3	)
Impact to basic net income per limited partner unit(5)	$	(0.14	)	$	(0.22	)	$	(0.45	)	$	(0.32	)
Impact to diluted net income per limited partner unit(5)	$	(0.13	)	$	(0.22	)	$	(0.45	)	$	(0.32	)

(1)	The Long-Term Incentive Plan (“LTIP”) charge for the three month and six month periods ended June 30, 2007 excludes the portion of the LTIP expense represented by LTIP grants under the 2006 Plan that, pursuant to the terms of the Plan, will be settled in cash only and have no impact on diluted units.
(2)	During the first quarter of 2006, we adopted SFAS No. 123(R) “Share Based Payment,” which requires that the cost resulting from all share-based payment transactions be recognized in the financial statements at fair value. The cumulative adjustment decreased our LTIP life-to-date accrued expense and related liability, and therefore resulted in a non-cash gain of $6.3 million in the first quarter of 2006.
(3)	The SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, as amended (“SFAS 133”) charge for three and six month periods ended June 30, 2007, includes a $0.3 million loss related to fair value hedge of debt instrument which does not impact segment profit.
(4)	Includes the initial cumulative effect of the recent change in Canadian tax legislation.
(5)	In periods when the Partnership’s net income exceeds the cash distribution paid during such periods the application of Emerging Issues Task Force Issue No. 03-06, “Participating Securities and the Two Class Method under FASB Statement No 128” (“EITF 03-06”) does not impact the partnership’s aggregate net income or EBITDA, but does reduce the Partnership’s net income per limited partner unit. The application of EITF 03-06 negatively impacted basic and diluted earnings per limited partner unit by $0.11 for the three months ended June 30, 2006 and $0.15 for the six months ended June 30, 2006. The application of EITF 03-06 had no impact on our results for the three and six months ended June 30, 2007.

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The following tables present certain selected financial information by segment for the second-quarter reporting periods:

	Three Months Ended June 30, 2007									Three Months Ended June 30, 2006
	Transportation			Facilities			Marketing			Transportation			Facilities			Marketing
	Operations			Operations			Operations			Operations			Operations			Operations
	(In millions)									(In millions)
Revenues(1)	$	194.2		$	54.2		$	3,787.5		$	130.9		$	21.4		$	4,797.4
Purchases and related costs(1)		(20.5	)		—			(3,627.2	)		(18.6	)		—			(4,696.4	)
Field operating costs (excluding LTIP charge)		(73.2	)		(21.3	)		(38.4	)		(46.8	)		(8.9	)		(33.1	)
LTIP charge — operations		(2.5	)		(0.1	)		(0.2	)		(0.6	)		—			—
Segment G&A expenses (excluding LTIP charge)(2)		(11.2	)		(4.6	)		(12.9	)		(9.5	)		(4.5	)		(7.8	)
LTIP charge — general and administrative		(8.3	)		(3.1	)		(7.6	)		(2.5	)		(1.0	)		(2.1	)
Equity earnings in unconsolidated entities		1.2			3.8			—			0.5			1.1			—
Segment profit	$	79.7		$	28.9		$	101.2		$	53.4		$	8.1		$	58.0
SFAS 133 mark-to-market impact(3)	$	—		$	—		$	15.2		$	—		$	—		$	(2.4	)
Maintenance capital	$	9.2		$	2.4		$	(0.7	)	$	3.4		$	0.7		$	0.3

	Six Months Ended June 30, 2007									Six Months Ended June 30, 2006
	Transportation			Facilities			Marketing			Transportation			Facilities			Marketing
	Operations			Operations			Operations			Operations			Operations			Operations
	(In millions)									(In millions)
Revenues(1)	$	372.4		$	99.3		$	7,897.1		$	248.8		$	33.3		$	13,357.7
Purchases and related costs(1)		(38.0	)		—			(7,612.7	)		(36.8	)		—			(13,157.7	)
Field operating costs (excluding LTIP charge)		(139.6	)		(40.2	)		(76.6	)		(93.7	)		(14.4	)		(64.7	)
LTIP charge — operations		(4.6	)		(0.1	)		(0.3	)		(1.7	)		—			(0.1	)
Segment G&A expenses (excluding LTIP charge)(2)		(23.8	)		(9.5	)		(25.8	)		(19.4	)		(7.0	)		(17.8	)
LTIP charge — general and administrative		(15.7	)		(5.2	)		(14.5	)		(6.5	)		(2.2	)		(6.3	)
Equity earnings in unconsolidated entities		2.1			6.5			—			0.8			0.9			—
Segment profit	$	152.8		$	50.8		$	167.2		$	91.5		$	10.6		$	111.1
SFAS 133 mark-to-market impact(3)	$	—		$	—		$	(1.8	)	$	—		$	—		$	(3.1	)
Maintenance capital	$	12.4		$	6.2		$	3.1		$	6.4		$	1.5		$	1.2

(1)	Includes intersegment amounts. Effective April 1, 2006, we adopted EITF 04-13, which impacts the comparability of our revenues and purchases. Revenues and purchases for the six months ended June 30, 2006 include buy/sell transactions of $4,761.9 million. Revenues and purchases from such transactions are excluded from the six-month period ended June 30, 2007.
(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 judgement by management and will continue to be based on the business activities that exist during each period.
(3)	Amounts related to SFAS 133 are included in revenues and impact segment profit. The SAFS 133 mark-to-market adjustment is primarily based upon crude oil prices at the end of the period and is related to the non-effective portion of our cash flow hedges, as well as certain derivative contracts that do not qualify under SFAS 133 as cash flow hedges. The net gain or loss related to these derivative instruments is

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principally offset by physical positions in future periods. The SFAS 133 amount for the three and six month periods ended June 30, 2007 excludes a $0.3 million loss related to a fair value hedge of a debt instrument, which is included in net income but does not impact segment profit.

Excluding selected items impacting comparability, segment profit from Transportation operations in the second quarter of 2007 was $89.4 million, 58% higher than second quarter 2006 segment results of $56.5 million. Transportation volumes for the second quarter of 2007 were 2.9 million barrels per day versus 2.1 million barrels per day in the second quarter of 2006.

Adjusted segment profit for Facilities operations for the second quarter of 2007 was $31.8 million representing a 249% increase over adjusted Facilities operations segment profit of $9.1 million for the second quarter of 2006, reflecting increased storage capacity and throughput activity due to the Pacific acquisition and the completion of new capital projects.

Marketing operations adjusted segment profit of $92.9 million for the second quarter of 2007 represents an increase of 49% over the second quarter 2006 results of $62.5 million reflecting an expanded asset base and favorable market conditions.

The Partnership realized an approximate $9 million net loss on the sale of assets during the second quarter of 2007, which is reflected as an increase in depreciation expense. As a result of recent Canadian tax legislation that may apply to a portion of PAA’s Canadian activities, the Partnership also recorded a $10.8 million deferred tax provision related to the cumulative effect of this tax which is primarily attributable to prior years.

The Partnership’s basic weighted average units outstanding for the second quarter of 2007 totaled 110.5 million (111.2 million diluted) as compared to 77.0 million (77.8 million diluted) in last year’s second quarter. At June 30, 2007, the Partnership had approximately 116.0 million units outstanding, long-term debt of $2.6 billion and a long-term debt-to-total capitalization percentage of 44%.

On July 19, 2007, the Partnership declared a cash distribution of $0.83 per unit ($3.32 per unit on an annualized basis) on its outstanding limited partner units. The distribution will be payable on August 14, 2007, and represents an increase of 14.5% over the distribution paid in August 2006 and 2.2% over the distribution paid in May 2007. This represents the 13th consecutive increase in quarterly distributions for the Partnership and the 20th increase in the last twenty-six quarters.

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 and fourth quarter and full year 2007. 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 and exchange rates, as well as mechanical interruptions, acquisitions and numerous other factors. These types of variations are not

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separately identified in this release, but will be discussed in management’s discussion and analysis of operating results in our Quarterly Report on Form 10-Q.

A reconciliation of EBITDA to net income and cash flows from operating activities for the 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, that it reconciles 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 tab.

Conference Call

The Partnership will host a conference call on Tuesday, August 7, 2007 to discuss the following items:

1. The Partnership’s second quarter 2007 performance;

2. Status of major expansion capital projects and recent acquisition activity;

3. Capitalization, liquidity and recent financing activities;

4. Financial and operating guidance for the third quarter and full year 2007; and

5. The Partnership’s outlook for the future.

The call will begin at 10:00 AM (Central). To participate in the call, please dial 877-709-8150 or, for international callers, 201-689-8354, at approximately 9:55 AM (Central). No password or reservation number is required.

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.

Telephonic Replay Instructions

To listen to a telephonic replay of the conference call, please dial 877-660-6853 or, for international callers, 201-612-7415, and enter account number 232 and replay number 248168. The replay will be available beginning Tuesday, August 7, 2007, at approximately 1:00 PM (Eastern) and continue until 11:59 PM (Eastern) Monday, August 13, 2007.

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 50% ownership in PAA/Vulcan Gas Storage LLC, the partnership also develops and operates natural gas storage facilities. The Partnership is headquartered in Houston, Texas.

Forward Looking Statements

Except for the historical information contained herein, the matters discussed in this news 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: the failure to realize the anticipated synergies and other benefits of the merger with Pacific Energy; the success of our risk management activities; environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves; maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties; abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems; failure to implement or capitalize on planned internal

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growth projects; 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; 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 transmission throughput requirements; the availability of, and our ability to consummate, acquisition or combination opportunities; our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms; 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 and governmental regulations; the effects of competition; continued creditworthiness of, and performance by, our counterparties; 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; general economic, market or business conditions; 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.

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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,
	2007			2006			2007			2006
REVENUES(1)	$	3,917.8		$	4,892.0		$	8,147.3		$	13,527.1
COSTS AND EXPENSES
Purchases and related costs(1)		3,529.6			4,657.3			7,429.2			13,081.8
Field operating costs		135.7			89.4			261.4			174.6
General and administrative expenses		47.7			27.4			94.5			59.2
Depreciation and amortization		52.1			21.3			92.0			42.9
Total costs and expenses		3,765.1			4,795.4			7,877.1			13,358.5
OPERATING INCOME		152.7			96.6			270.2			168.6
OTHER INCOME/(EXPENSE)
Equity earnings in unconsolidated entities		5.0			1.6			8.6			1.7
Interest expense		(41.2	)		(18.0	)		(82.3	)		(33.3	)
Interest income and other income (expense), net		0.4			0.1			5.2			0.4
Income before tax		116.9			80.3			201.7			137.4
Current income tax expense		(0.7	)		—			(0.8	)		—
Deferred income tax expense		(11.4	)		—			(11.4	)		—
Income before cumulative effect of change in accounting principle		104.8			80.3			189.5			137.4
Cumulative effect of change in accounting principle		—			—			—			6.3
NET INCOME	$	104.8		$	80.3		$	189.5		$	143.7
NET INCOME — LIMITED PARTNERS	$	86.3		$	71.4		$	154.4		$	128.2
NET INCOME — GENERAL PARTNER	$	18.5		$	8.9		$	35.1		$	15.5
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.78		$	0.82		$	1.40		$	1.47
Cumulative effect of change in accounting principle		—			—			—			0.08
Basic net income per limited partner unit	$	0.78		$	0.82		$	1.40		$	1.55
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.78		$	0.81		$	1.39		$	1.45
Cumulative effect of change in accounting principle		—			—			—			0.08
Diluted net income per limited partner unit	$	0.78		$	0.81		$	1.39		$	1.53
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING		110.5			77.0			109.9			75.5
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING		111.2			77.8			110.9			76.3

⁽¹⁾ Revenues and purchases include buy/sell transactions of $4.8 billion in the three months ended March 31, 2006.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

OPERATING DATA⁽¹⁾

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Transportation activities (Average Daily Volumes, thousands of barrels):
Tariff activities
All American		47		53		48		48
Basin		407		330		374		322
Capline		231		178		233		132
Line 63 / Line 2000		181		N/A		181		N/A
Salt Lake City		64		N/A		63		N/A
North Dakota/Trenton		98		87		96		85
West Texas/New Mexico area systems(2)		395		478		381		460
Manito		74		73		74		69
Refined products		105		N/A		110		N/A
Other		1,170		802		1,131		792
		2,772		2,001		2,691		1,908
Trucking volumes		107		103		108		114
Transportation activities total		2,879		2,104		2,799		2,022
Facilities activities (Average Monthly Volumes):
Crude oil, refined products, and LPG storage (average monthly capacity in millions of barrels)		36.0		19.0		35.6		18.7
Natural gas storage, net to our 50% interest (average monthly capacity in billions of cubic feet)		12.9		12.9		12.9		12.2
LPG processing (thousands of barrels per day)		20.0		18.0		16.9		9.1
Facilities activities total (average monthly capacity in millions of barrels)(3)		38.8		21.7		38.3		21.0
Marketing activities (Average Daily Volumes, thousands of barrels):
Crude oil lease gathering		707		652		694		637
Refined Products		13		N/A		8		N/A
LPG sales		45		25		89		54
Waterborne foreign crude imported		78		43		72		50
Marketing activities total		843		720		863		741

(1)	Volumes associated with acquisitions represent total volumes transported 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 West Texas/New Mexico area.
(3)	In order to calculate total facilities activities volume add: (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 1,000 to convert to monthly volumes in millions.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(In millions)

	June 30,		December 31,
	2007		2006
ASSETS
Current assets	$	3,462.4	$	3,157.6
Property and equipment, net		4,086.8		3,842.0
Pipeline linefill in owned assets		248.3		265.5
Inventory in third-party assets		64.1		75.7
Investment in unconsolidated entities		200.1		183.0
Goodwill		1,045.5		1,026.2
Other long-term assets, net		157.0		164.9
Total assets	$	9,264.2	$	8,714.9
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	3,115.7	$	3,024.7
Long-term debt under credit facilities and other		1.2		3.1
Senior notes, net of unamortized net discount		2,623.1		2,623.2
Other long-term liabilities and deferred credits		124.6		87.1
Total liabilities		5,864.6		5,738.1
Partners’ capital		3,399.6		2,976.8
Total liabilities and partners’ capital	$	9,264.2	$	8,714.9

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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						Six Months
	Ended						Ended
	June 30,						June 30,
	2007			2006			2007			2006
Numerator for basic and diluted earnings per limited partner unit:
Net income	$	104.8		$	80.3		$	189.5		$	143.7
Less: General partner’s incentive distribution paid		(16.7	)		(7.4	)		(32.0	)		(12.9	)
Subtotal		88.1			72.9			157.5			130.8
Less: General partner 2% ownership		(1.8	)		(1.5	)		(3.1	)		(2.6	)
Net income available to limited partners		86.3			71.4			154.4			128.2
Less: Pro forma additional general partner’s distribution(1)		—			(8.2	)		—			(11.2	)
Net income available for limited partners under EITF 03-06		86.3			63.2			154.4			117.0
Less: Limited partner 98% portion of cumulative effect of change in accounting principle		—			—			—			(6.2	)
Limited partner net income before cumulative effect of change in accounting principle	$	86.3		$	63.2		$	154.4		$	110.8
Denominator:
Basic weighted average number of limited partner units outstanding		110.5			77.0			109.9			75.5
Effect of dilutive securities:
Weighted average LTIP units		0.7			0.8			1.0			0.8
Diluted weighted average number of limited partner units outstanding		111.2			77.8			110.9			76.3
Basic net income per limited partner unit before cumulative effect of change in accounting principle(1)	$	0.78		$	0.82		$	1.40		$	1.47
Cumulative effect of change in accounting principle per limited partner unit(1)		—			—			—			0.08
Basic net income per limited partner unit(1)	$	0.78		$	0.82		$	1.40		$	1.55
Diluted net income per limited partner unit before cumulative effect of change in accounting principle(1)	$	0.78		$	0.81		$	1.39		$	1.45
Cumulative effect of change in accounting principle per limited partner unit(1)		—			—			—			0.08
Diluted net income per limited partner unit(1)	$	0.78		$	0.81		$	1.39		$	1.53

⁽¹⁾ Reflects pro forma full distribution of earnings under EITF 03-06. The application of EITF 03-06 negatively impacted basic and diluted earnings per limited partner unit by approximately $0.11 for the three months ended June 30, 2006 and $0.15 for the six months ended June 30, 2006. The application of EITF 03-06 had no impact on our results for the three and six months ended June 30, 2007.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Earnings before interest, taxes, depreciation and amortization (“EBITDA”)
Net income reconciliation
EBITDA	$	210.2		$	119.6		$	376.0		$	219.9
Depreciation and amortization		(52.1	)		(21.3	)		(92.0	)		(42.9	)
Earnings before interest and taxes (“EBIT”)		158.1			98.3			284.0			177.0
Interest expense		(41.2	)		(18.0	)		(82.3	)		(33.3	)
Income tax expense		(12.1	)		—			(12.2	)		—
Net income	$	104.8		$	80.3		$	189.5		$	143.7
Cash flow from operating activities reconciliation
EBITDA	$	210.2		$	119.6		$	376.0		$	219.9
Interest expense		(41.2	)		(18.0	)		(82.3	)		(33.3	)
Net change in assets and liabilities, net of acquisitions		(268.9	)		(294.2	)		(51.0	)		(843.0	)
Other items to reconcile to cash flows from operating activities:
Cumulative effect of change in accounting principle		—			—			—			(6.3	)
Equity earnings in unconsolidated entities		(4.4	)		(1.6	)		(7.8	)		(1.7	)
Inventory valuation adjustment		(0.4	)		—			0.6			—
Gain on sale of investment assets		—			—			(3.9	)		—
Net (gain) / loss on foreign currency revaluation		(1.8	)		0.9			(2.0	)		1.8
SFAS 133 mark-to-market adjustment		(14.9	)		2.4			2.1			3.1
LTIP charge		21.8			6.2			40.4			16.8
Non-cash amortization of terminated interest rate hedging instruments		0.2			0.4			0.4			0.8
Net cash provided by (used in) operating activities	$	(99.4	)	$	(184.3	)	$	272.5		$	(641.9	)

	Three Months Ended						Six Months Ended
	June 30,						June, 30
	2007			2006			2007			2006
Funds flow from operations (“FFO”)
Net income	$	104.8		$	80.3		$	189.5		$	143.7
Undistributed equity earnings in unconsolidated entities		(4.4	)		(0.9	)		(7.8	)		(0.6	)
Depreciation and amortization		52.1			21.3			92.0			42.9
Deferred income tax expense		11.4			—			11.4			—
Non-cash amortization of terminated interest rate hedging instruments		0.2			0.4			0.4			0.8
FFO		164.1			101.1			285.5			186.8
Maintenance capital expenditures		(10.9	)		(4.4	)		(21.7	)		(9.1	)
FFO after maintenance capital expenditures	$	153.2		$	96.7		$	263.8		$	177.7

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

FINANCIAL DATA RECONCILIATIONS (continued)

(In millions, except per unit data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Selected items impacting comparability
LTIP charge(1)	$	(19.5	)	$	(6.2	)	$	(37.4	)	$	(16.8	)
Cumulative effect of change in accounting principle — LTIP(2)		—			—			—			6.3
SFAS 133 mark-to-market adjustment(3)		14.9			(2.4	)		(2.1	)		(3.1	)
Deferred income tax expense(4)		(10.8	)		—			(10.8	)		—
Selected items impacting comparability		(15.4	)		(8.6	)		(50.3	)		(13.6	)
Less: GP 2% portion of selected items impacting comparability		0.3			0.2			1.0			0.3
LP 98% portion of selected items impacting comparability	$	(15.1	)	$	(8.4	)	$	(49.3	)	$	(13.3	)
Impact to basic net income per limited partner unit(5)	$	(0.14	)	$	(0.22	)	$	(0.45	)	$	(0.32	)
Impact to diluted net income per limited partner unit(5)	$	(0.13	)	$	(0.22	)	$	(0.45	)	$	(0.32	)

(1)	The LTIP charge for the three month and six month periods ended June 30, 2007 excludes the portion of the LTIP expense represented by LTIP grants under the 2006 Plan that, pursuant to the terms of the Plan, will be settled in cash only and have no impact on diluted units.
(2)	During the first quarter of 2006, we adopted SFAS No. 123(R) “Share Based Payment,” which requires that the cost resulting from all share-based payment transactions be recognized in the financial statements at fair value. The cumulative adjustment decreased our LTIP life-to-date accrued expense and related liability, and therefore resulted in a non-cash gain of $6.3 million in the first quarter of 2006.
(3)	For three and six month periods ended June 30, 2007, includes a $0.3 million loss related to a fair value hedge of a debt instrument which does not impact segment profit.
(4)	Includes the initial cumulative effect of the recent change in Canadian tax litigation.
(5)	In periods when the Partnership’s net income exceeds the cash distribution paid during such periods the application of Emerging Issues Task Force Issue No. 03-06, “Participating Securities and the Two Class Method under FASB Statement No 128” (“EITF 03-06”) does not impact the partnership’s aggregate net income or EBITDA, but does reduce the Partnership’s net income per limited partner unit. The application of EITF 03-06 negatively impacted basic and diluted earnings per limited partner unit by $0.11 for the three months ended June 30, 2006 and $0.15 for the six months ended June 30, 2006. The application of EITF 03-06 had no impact on our results for the three and six months ended June 30, 2007.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

FINANCIAL DATA RECONCILIATIONS (continued)

(In millions, except per unit data)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
Net income and earnings per limited partner unit excluding selected items impacting comparability
Net income	$	104.8	$	80.3	$	189.5	$	143.7
Selected items impacting comparability		15.4		8.6		50.3		13.6
Adjusted net income	$	120.2	$	88.9	$	239.8	$	157.3
Net income available for limited partners under EITF 03-06	$	86.3	$	63.2	$	154.4	$	117.0
Limited partners 98% of selected items impacting comparability		15.1		8.4		49.3		13.3
Pro forma additional general partner distribution under EITF 03-06		—		8.2		—		11.2
Adjusted limited partners net income	$	101.4	$	79.8	$	203.7	$	141.5
Adjusted basic net income per limited partner unit	$	0.92	$	1.04	$	1.85	$	1.87
Adjusted diluted net income per limited partner unit	$	0.91	$	1.03	$	1.84	$	1.85
Basic weighted average units outstanding		110.5		77.0		109.9		75.5
Diluted weighted average units outstanding		111.2		77.8		110.9		76.3

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

FINANCIAL DATA RECONCILIATIONS(continued)

(In millions, except per unit data)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2007		2006		2007		2006
EBITDA excluding selected items impacting comparability
EBITDA	$	210.2	$	119.6	$	376.0	$	219.9
Selected items impacting comparability(1)		4.6		8.6		39.5		13.6
Adjusted EBITDA	$	214.8	$	128.2	$	415.5	$	233.5

	Three Months Ended							Six Months Ended
	June 30, 2007							June 30, 2007
	Transportation		Facilities		Marketing			Transportation		Facilities		Marketing
2007 Segment profit excluding selected items impacting comparability
Reported segment profit	$	79.7	$	28.9	$	101.2		$	152.8	$	50.8	$	167.2
Selected items impacting comparability of segment profit:
LTIP charge		9.7		2.9		6.9			18.9		4.9		13.6
SFAS 133 mark-to-market adjustment(2)		—		—		(15.2	)		—		—		1.8
Segment profit excluding selected items impacting comparability	$	89.4	$	31.8	$	92.9		$	171.7	$	55.7	$	182.6

	Three Months Ended						Six Months Ended
	June 30, 2006						June 30, 2006
	Transportation		Facilities		Marketing		Transportation		Facilities		Marketing
2006 Segment profit excluding selected items impacting comparability
Reported segment profit	$	53.4	$	8.1	$	58.0	$	91.5	$	10.6	$	111.1
Selected items impacting comparability of segment profit:
LTIP charge		3.1		1.0		2.1		8.2		2.2		6.4
SFAS 133 mark-to-market adjustment		—		—		2.4		—		—		3.1
Segment profit excluding selected items impacting comparability	$	56.5	$	9.1	$	62.5	$	99.7	$	12.8	$	120.6

(1)	Excludes deferred income tax expense as it does not impact EBITDA.
(2)	The SFAS 133 amount for the three and six month periods ended June 30, 2007 excludes a $0.3 million loss related to a fair value hedge of a debt instrument, which is included in interest income and other income (expense), net but does not impact segment profit.

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