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)—November 2, 2006

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

Press Release

Item 9.01. Financial Statements and Exhibits

     (d) Exhibit 99.1—Press release dated November 2, 2006

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 third quarter 2006 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 fourth quarter (which supersedes guidance in our 8-K furnished on August 1, 2006) of calendar 2006 and resulting financial performance for the full year of calendar 2006. The Partnership’s guidance excludes any contribution from the proposed merger with Pacific Energy Partners, L.P. (“Pacific Energy”) announced June 12, 2006. Note 12 includes the estimated impact of the Pacific Energy acquisition to our fourth quarter, assuming the acquisition closes on November 15, 2006. 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.

Update of Fourth Quarter 2006 Estimates

     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 11 below, we reconcile EBITDA and EBIT to net income for the 2006 guidance periods presented. However, it is 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, the cumulative effect of a change in accounting principle, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments) to the extent known, interest expense related to our New Senior Notes (as defined in Note 7) and interest income from the investment of the net proceeds from the New Senior Notes on EBITDA, Net Income and Net Income per Basic and Diluted Limited Partner Unit.

     The following guidance for the three month period ending December 31, 2006 is based on assumptions and estimates that we believe are reasonable given our assessment of historical trends, business cycles and other information reasonably available. However, our assumptions and future performance 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 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 November 1, 2006. 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*
	Nine Months			Three Months Ending						Twelve Months Ending
	Ended			December 31, 2006						December 31, 2006
	09/30/06			Low			High			Low			High
Pipeline
Net revenues	$	319.4		$	110.3		$	111.7		$	429.7		$	431.1
Field operating costs		(138.1	)		(47.2	)		(46.6	)		(185.3	)		(184.7	)
General and administrative expenses		(38.0	)		(12.4	)		(12.2	)		(50.4	)		(50.2	)
		143.3			50.7			52.9			194.0			196.2
Gathering, Marketing, Terminalling & Storage
Net revenues		382.8			115.0			121.4			497.8			504.2
Field operating costs		(122.4	)		(43.0	)		(42.4	)		(165.4	)		(164.8	)
General and administrative expenses		(54.2	)		(19.9	)		(19.6	)		(74.1	)		(73.8	)
		206.2			52.1			59.4			258.3			265.6
Segment Profit		349.5			102.8			112.3			452.3			461.8
Depreciation and amortization expense		(67.1	)		(27.0	)		(26.6	)		(94.1	)		(93.7	)
Interest expense — existing notes and facilities		(52.5	)		(20.1	)		(19.3	)		(72.6	)		(71.8	)
Interest expense — New Senior Notes (See Note 7 & 8)		—			(10.8	)		(10.8	)		(10.8	)		(10.8	)
Interest income — New Senior Notes (See Note 7 & 8)		—			8.7			8.7			8.7			8.7
Equity earnings (loss) in PAA / Vulcan Gas Storage, LLC		2.2			2.8			3.3			5.0			5.5
Other Income (Expense)		0.7			—			—			0.7			0.7
Income Before Cumulative Effect of Change in Accounting Principle		232.8			56.4			67.6			289.2			300.4
Cumulative Effect of Change in Accounting Principle		6.3			—			—			6.3			6.3
Net Income	$	239.1		$	56.4		$	67.6		$	295.5		$	306.7
Net Income to Limited Partners	$	212.7		$	44.4		$	55.4		$	257.1		$	268.1
Basic Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		77.0			81.0			81.0			78.0			78.0
Net Income Per Unit **	$	2.45		$	0.55		$	0.68		$	3.09		$	3.16
Diluted Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		77.8			82.0			82.0			78.8			78.8
Net Income Per Unit **	$	2.43		$	0.54		$	0.67		$	3.06		$	3.13
EBIT	$	291.6		$	78.6		$	89.0		$	370.2		$	380.6
EBITDA	$	358.7		$	105.6		$	115.6		$	464.3		$	474.3

Selected Items Impacting Comparability
LTIP charge	$	(27.1	)	$	(9.4	)	$	(9.4	)	$	(36.5	)	$	(36.5	)
Cumulative Effect of Change in Accounting Principle		6.3			—			—			6.3			6.3
SFAS 133 Mark-to-Market Adjustment		14.8			—			—			14.8			14.8
Interest expense — New Senior Notes		—			(10.8	)		(10.8	)		(10.8	)		(10.8	)
Interest income — New Senior Notes		—			8.7			8.7			8.7			8.7
	$	(6.0	)	$	(11.5	)	$	(11.5	)	$	(17.5	)	$	(17.5	)

Excluding Selected Items Impacting Comparability
Adjusted EBITDA	$	364.7	$	115.0	$	125.0	$	479.7	$	489.7
Adjusted Net Income	$	245.1	$	67.9	$	79.1	$	313.0	$	324.2
Adjusted Basic Net Income per Limited Partner Unit	$	2.84	$	0.69	$	0.82	$	3.53	$	3.66
Adjusted Diluted Net Income per Limited Partner Unit	$	2.81	$	0.68	$	0.81	$	3.49	$	3.62

*	The projected average foreign exchange rate is $1.15 CAD to $1 USD. The rate as of November 1, 2006 was 1.13 CAD to $1 USD.
**	See Note 9. The application of EITF 03-06 may result in interim period amounts not totaling to the annual amount.

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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
Bbls/d	Barrels per day
Segment Profit	Net revenues 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
GMT&S	Gathering, Marketing, Terminalling & Storage

2.

Pipeline Operations. 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. Actual segment profit could vary materially depending on the level of volumes transported.

The following table summarizes our total pipeline volumes and highlights as major systems that are significant either in total volumes transported or in contribution to total pipeline segment profit.

	Calendar 2006
	Actual			Guidance
	Nine Months			Three Months			Twelve Months
	Ended			Ending			Ending
	September 30			December 31			December 31
Average Daily Volumes (000 Bbls/d)
All American		49			45			48
Basin		323			350			330
BOA / CAM		57	(1)		172			86
Capline		149			185			158
Cushing to Broome		73			80			75
North Dakota / Trenton		88			92			89
West Texas / New Mexico area systems (2)		445			428			441
Canada		247			254			250
Other		553			580	(3)		558
		1,984			2,186			2,035
Average Segment Profit ($/Bbl)
As Reported	$	0.27		$	0.26	(4)	$	0.26	(4)
Excluding Selected Items Impacting Comparability	$	0.29		$	0.28	(4)	$	0.29	(4)

(1)	Acquisition effective in third quarter of 2006.
(2)	The aggregate of multiple systems in the West Texas / New Mexico area.
(3)	Includes approximately 45,000 Bbl/d related to assets purchased from Chevron Pipe Line Company effective September 1, 2006.
(4)	Mid-point of guidance.

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Segment profit is forecast using the volume assumptions in the table above, priced at tariff rates currently received, less estimated field operating costs and G&A expenses. Field operating costs do not include depreciation.

To illustrate the impact volume changes may have on fourth quarter segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 28% of total pipeline net revenues.

Volume Sensitivity Analysis
			% of			Incr (Decr)
	Incr (Decr)		System			in Segment
System	in Volume		Total			Profit Guidance
	(Bbls/d)					(in millions)
All American		5,000		11	%	$	0.9
Basin		20,000		6	%		0.5
Capline		10,000		5	%		0.3

3. Gathering, Marketing, Terminalling and Storage Operations. The level of profit in the GMT&S segment is influenced by overall market structure and the degree of volatility in the crude oil market as well as variable operating expenses. Operating results for the three-month period ending December 31, 2006 reflect an expected continuation of the current contango market and favorable market conditions (relative to our asset base and business model) generally consistent with the conditions experienced over most of 2005 and 2006 to date, although not quite as favorable as market conditions in the first nine months of 2006. Unexpected changes in market structure or volatility (or lack thereof) could cause actual results to differ materially from forecasted results.

	Calendar 2006
	Actual		Guidance
	Nine Months		Three Months			Twelve Months
	Ended		Ending			Ending
	September 30		December 31			December 31
Average Daily Volumes (000 Bbls/d)
Crude Oil Lease Gathering		639		650			642
LPG Sales and Third Party Processing		60		90			68
Waterborne foreign crude imported		59		50			57
		758		790			767
Segment Profit per Barrel ($/Bbl)
As Reported	$	1.00	$	0.77	(1)	$	0.94	(1)
Excluding Selected Items Impacting Comparability	$	1.00	$	0.83	(1)	$	0.95	(1)

(1) Mid-point of guidance.

Segment profit is forecast using the volume assumptions stated above 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. Based on our mid-point projection of adjusted segment profit per barrel for the three months ending December 31, 2006, a 15,000 Bbl/d variance in lease gathering volumes would impact fourth-quarter segment profits by approximately $1.0 million. A $0.01 variance in the aggregate average per-barrel margin would impact fourth-quarter segment profits by approximately $0.7 million.

4. Depreciation and Amortization. Depreciation and amortization are forecast based on our existing depreciable assets and forecasted capital expenditures. 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).

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5. Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). The guidance presented above does not include assumptions or projections 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.

6. Acquisitions and Capital Expenditures. Although acquisitions constitute a key element of our growth strategy, the forecasted results and associated estimates do not include any assumptions or forecasts for any other acquisition that may be made after the date hereof. Capital expenditures for expansion projects are forecast to be approximately $310 million during calendar 2006 of which $214 million was incurred in the first nine months of 2006. Following are some of the more notable projects and estimated expenditures for the year.

	Calendar 2006
	(in millions)
Expansion Capital
• St. James, Louisiana storage facility — Phase I	$	72
• St. James, Louisiana storage facility — Phase II		12
• Kerrobert tankage		31
• East Texas/Louisiana tankage		17
• Spraberry System expansion		15
• Cushing Tankage — Phase VI		14
• High Prairie rail terminals		13
• Midale/Regina truck terminal		13
• Truck trailers		9
• Wichita Falls tankage		8
• Basin connection—Oklahoma		8
• Mobile/ Ten Mile tankage and metering		6
• Other Projects		92
		310
Maintenance Capital		21
Total Projected Capital Expenditures (excluding acquisitions)	$	331

7.

Capital Structure. This guidance is based on our capital structure as of September 30, 2006 as adjusted to give effect to the aggregate $1 billion private placement of 10-year and 30-year senior notes (“New Senior Notes”) that closed on October 30, 2006. The net proceeds from the New Senior Notes will be used to fund the cash portion of the Pacific Energy acquisition expected to close in the fourth quarter of 2006. Pending closing of the Pacific Energy merger, we intend to invest excess proceeds that are not used to repay outstanding indebtedness or for general partnership purposes in short-term investments. In the event the Pacific Energy acquisition does not close by February 15, 2007, we are required to call the New Senior Notes at 101% of the principal amount. See Note 8 for treatment of interest expense and interest income attributable to the New Senior Notes during the fourth quarter.

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.

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8.	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.
	Interest expense for the three months ending December 31, 2006 is expected to be between $19.3 million and $20.1 million, assuming an average long-term debt balance excluding the New Senior Notes of approximately $1.3 billion during the period and an all-in average rate of approximately 6.2%. Included in the effective cost of debt are projected interest payments, as well as commitment fees, amortization of long-term debt discounts, 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 International Petroleum Exchange margin deposits). At September 30, 2006, 100% of our long-term debt balance was fixed at an average interest rate of 6.1%. Interest expense does not include interest on borrowings for contango inventory. We treat those costs as carrying costs of crude oil and include it as part of the purchase price of crude oil.
	The amount of interest expense noted in the preceding paragraph excludes approximately $10.8 million of interest expense associated with the New Senior Notes discussed in Note 7 above, as well as approximately $8.7 million of interest income earned from investing the net proceeds from the notes offering pending closing of the Pacific Energy acquisition. These amounts are included as separate line items in our primary guidance table, but have been treated as Selected Items Impacting Comparability in arriving at Adjusted EBITDA and Adjusted Net Income. We believe this is consistent with our treatment of excluding any contribution from Pacific Energy in our guidance pending the closing of the acquisition. In the event the Pacific Energy acquisition does not close by February 15, 2007, we are required to call the New Senior Notes at 101% of the principal amount. See Note 12 for an estimate on Adjusted EBITDA and Adjusted Net Income of the impact of the Pacific Energy acquisition assuming the acquisition closes on November 15, 2006.
9.	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. Under Emerging Issues Task Force Issue 03-06: Participating Securities and the Two-Class Method under FASB Statement No. 128 (“EITF 03-06”), when the Partnership’s aggregate net income exceeds the aggregate distribution made during such period, earnings per limited partner unit are calculated as if all of the earnings for the period were distributed, regardless of the pro forma nature of the allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. Although EITF 03-06 does not impact overall net income or other financial results of the Partnership, for periods in which aggregate net income exceeds the aggregate distributions for such period, earnings per limited partner unit will be reduced. The following table sets forth the computation of basic and diluted earnings per limited partner unit.

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	Guidance (in millions, except per unit data)
	Three Months Ending						Twelve Months Ending
	December 31, 2006						December 31, 2006
	Low			High			Low			High
Numerator for basic and diluted earnings per limited partner unit:
Net Income	$	56.4		$	67.6		$	295.5		$	306.7
Less:
General partner’s incentive distribution		(11.1	)		(11.1	)		(33.1	)		(33.1	)
		45.3			56.5			262.4			273.6
General partner 2% ownership		(0.9	)		(1.1	)		(5.3	)		(5.5	)
Net income available to limited partners		44.4			55.4			257.1			268.1
Pro forma additional general partner’s distribution		—			—			(16.1	)		(21.5	)
Net Income available for limited partners under EITF 03-06	$	44.4		$	55.4		$	241.0		$	246.6
Denominator:
Denominator for basic earnings per limited partner unit-weighted average number of limited partner units		81.0			81.0			78.0			78.0
Effect of dilutive securities:
Weighted average LTIP units		1.0			1.0			0.8			0.8
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units		82.0			82.0			78.8			78.8
Basic net income per limited partner unit	$	0.55		$	0.68		$	3.09		$	3.16
Diluted net income per limited partner unit	$	0.54		$	0.67		$	3.06		$	3.13

	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 partnership 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 $3.00 per unit, our general partner’s distribution is forecast to be approximately $49.3 million annually, of which $44.3 million is attributed to the incentive distribution rights. The relative amount of the incentive distribution varies directionally with the number of units outstanding and the level of the distribution on the units. For distribution rates where EITF 03-06 does not apply, each $0.05 per unit annual increase in the distribution over $3.00 per unit decreases net income available for limited partners by approximately $4.0 million ($0.05 per unit) on an annualized basis.
10.	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 2007 to December 2010 and minimum annualized distribution levels range from $2.60 to $4.00. For some awards, a percentage of any remaining units will vest on a date certain in 2011 or 2012.
	We have reached the annualized distribution level of $3.00 and it has been deemed probable that the $3.20 distribution level will be achieved. Accordingly, guidance includes, for grants that vest at annualized distribution levels of $3.20 or less, an accrual over the corresponding service period at an assumed market price of $46.15 per unit as well as the fair value associated with awards that will vest on a date certain. For 2006, the guidance includes approximately $36.5 million of principally non-cash expense associated with these grants. The earliest significant vesting event for outstanding grants will occur in May 2007.

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	The actual amount of LTIP expense amortization in any given year will be directly influenced by our unit price at the end of each reporting period and the amount of amortization in the early years as well as new unit grants. Therefore, actual net income could differ materially from our projections.
	Effective January 1, 2006 we adopted SFAS 123(R) Share-Based Payment, resulting in a cumulative effect of change in accounting principle gain of $6.3 million.
11.	Reconciliation of EBITDA and EBIT to Net Income. The following table reconciles the 2006 guidance ranges for EBITDA and EBIT to net income.

	Guidance
	Three Months Ending				Twelve Months Ending
	December 31, 2006				December 31, 2006
	Low		High		Low		High
	(in millions)
Reconciliation to Net Income
EBITDA	$	105.6	$	115.6	$	464.3	$	474.3
Depreciation and amortization		27.0		26.6		94.1		93.7
EBIT		78.6		89.0		370.2		380.6
Interest expense — existing notes and facilities		20.1		19.3		72.6		71.8
Interest expense — New Senior Notes, net		2.1		2.1		2.1		2.1
Net Income	$	56.4	$	67.6	$	295.5	$	306.7

12. Combined Plains and Pacific Energy Guidance. Plains and Pacific Energy will each hold their respective unitholder meetings on November 9, 2006 seeking approval of the proposed merger between Plains and Pacific Energy. The following table presents adjusted EBITDA and adjusted net income for the combined entities assuming the proposed merger is approved and closing occurs on November 15, 2006. The Pacific Energy information is derived from Pacific Energy’s guidance contained in its press release dated November 1, 2006, however, it excludes the impact of anticipated transaction synergies and contributions from capital expansion projects under construction. Although we have not reviewed Pacific Energy’s calculation of its guidance ranges, we believe that the estimates are reasonable.

	For the Three Months Ending December 31, 2006
				Pacific			Combined
	Plains			Energy			Guidance
	(midpoint of guidance amounts; in millions)
Adjusted EBITDA	$	120.0		$	18.5	1	$	138.5
Interest Expense		(19.7	)		(11.2	)2		(30.9	)
Depreciation and amortization		(26.8	)		(5.6	)3		(32.4	)
Adjusted Net Income	$	73.5		$	1.7		$	75.2
Basic Units Outstanding		81.0			11.1			92.1
Diluted Units Outstanding		82.0			11.1			93.1
Adjusted Basic Net Income per Limited Partner Unit	$	0.76					$	0.67
Adjusted Diluted Net Income per Limited Partner Unit	$	0.75					$	0.66

1	Per Pacific Energy mid-point estimate of $36.9 million reported in its press release dated November 1, 2006 and prorated based on an assumed closing date of November 15, 2006. Excludes the impact of anticipated transaction synergies and contributions from capital expansion projects under construction.
2	As computed by PAA based on debt assumed from Pacific Energy and estimated cash paid on an assumed closing date of November 15, 2006. Such interest expense includes a forecast of interest incurred on the New Senior Notes from November 15, 2006 through the remainder of the year, but does not include interest expense on the New Senior Notes or interest income from investment of the proceeds for the period prior to November 15, 2006.
3	PAA estimate of depreciation and amortization on the acquired assets based on the straight-line method of depreciation over average useful lives ranging from 5 to 40 years. Depreciation and amortization estimates are based on estimated purchase price allocations assumptions used in PAA's Current Report on Form 8-K filed on August 24, 2006.

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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 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. However, the absence of these words 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:

• our failure to successfully integrate the respective business operations upon completion of the merger with Pacific Energy or our failure to successfully integrate any future acquisitions;

• the failure to realize the anticipated cost savings, synergies and other benefits of the proposed 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 system;

• declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by us and third party shippers;

• the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate;

• demand for natural gas or various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements;

• fluctuations in refinery capacity in areas supplied by our main lines;

• 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;

• the impact of crude oil and natural gas price fluctuations;

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

• 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 marketing, transportation, terminalling, gathering and storage of crude oil and liquefied petroleum gas.

     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:	PLAINS AAP, L. P., its general partner
	By:	PLAINS ALL AMERICAN GP LLC, its general partner
Date: November 2, 2006	By:	/s/ Phil Kramer
		Name:	Phil Kramer
		Title:	Executive Vice President and Chief Financial Officer

11

Exhibit Index

Exhibit No.	Description of Exhibit
99.1	Press release dated November 2, 2006

EX-99.1

Contacts:

Phillip D. Kramer

Executive VP and CFO

713/646-4560 – 800/564-3036

A. Patrick Diamond

Director, Strategic Planning

713/646-4487 – 800/564-3036

FOR IMMEDIATE RELEASE

Plains All American Reports Strong Financial Results
for Third Quarter 2006 – Net Income Climbs 38%;
Net Income Per Diluted Unit Increases 13%; EBITDA Up 33%

(Houston – November 2, 2006) Plains All American Pipeline, L.P. (NYSE: PAA) reported third quarter 2006 net income of $95.4 million, equivalent to $0.89 per diluted limited partner unit. These financial results represent increases of 38% and 13%, respectively, over net income of $69.0 million, or $0.79 per diluted limited partner unit, for the third quarter of 2005. For the first nine months of 2006, the Partnership reported net income of $239.1 million, or $2.43 per diluted limited partner unit, representing increases of 46% and 17%, respectively, over net income of $164.1 million, or $2.07 per diluted limited partner unit, for the first nine months of 2005.

As reported, earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the third quarter of 2006 were $138.8 million, an increase of 33% as compared with EBITDA of $104.6 million for the third quarter of 2005. EBITDA for the first nine months of 2006 was $358.7 million, an increase of 35% as compared with EBITDA of $266.6 million for the first nine months of 2005. (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.)

“2006 is on course to be PAA’s most productive year yet,” said Greg L. Armstrong, Chairman and CEO of Plains All American. “Through three quarters, we have delivered strong operating and financial results, generated more than $100 million of cash flow in excess of distributions and completed $577 million of accretive and strategic acquisitions. Upon payment of the quarterly distribution on November 14th, our 2006 distributions paid per unit will exceed distributions paid per unit in 2005 by 11.5%.”

“Looking forward, we believe we are positioned to finish the year with solid operating and financial performance and we are implementing a significant expansion capital program which provides a solid foundation for future growth,” continued Armstrong. “Yesterday we completed our eighth acquisition for $33 million and we expect to complete the $2.4 billion merger with Pacific Energy Partners, L.P. on November 15th.” Armstrong noted that the unitholder meetings to approve the merger will be held on November 9th and the response received from unitholders thus far has been positive.”

“Importantly, despite all of this growth-related activity, we have maintained a strong capital structure and a high level of liquidity by reinvesting excess cash flow and proactively raising equity in lock-step with our growth,” said Armstrong.

The Partnership’s reported results include the impact of various items that affect comparability between reporting periods. Adjusting for selected items impacting comparability, the Partnership’s third quarter 2006 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA were $87.8 million, $0.95 per diluted unit and $131.2 million, respectively. By way of comparison, the Partnership’s third quarter 2005 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA were $71.0 million,

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$0.95 per diluted unit, and $106.6 million, respectively. On a comparable basis, third quarter 2006 adjusted net income increased 24%, adjusted net income per diluted limited partner unit remained constant and adjusted EBITDA increased 23% over third quarter 2005.

The Partnership’s adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA for the first nine months of 2006 were $245.1 million, $2.81 per diluted unit and $364.7 million, respectively. The Partnership’s adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA for the first nine months of 2005 were $202.4 million, $2.73 per diluted unit and $304.9 million, respectively. On a comparable basis, adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA for the first nine months of 2006 increased 21%, 3% and 20%, respectively, in comparison with the first nine months of 2005.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
	(in millions, except per unit data)
Long-Term Incentive Plan (“LTIP”) charge	$	(10.3	)	$	(6.7	)	$	(27.1	)	$	(16.9	)
Cumulative effect of change in accounting principle – LTIP(1)		-			-			6.3			-
Gain/(loss) on foreign currency revaluation		-			(1.6	)		-			(1.4	)
SFAS 133 mark-to-market adjustment		17.9			6.3			14.8			(20.0	)
Total	$	7.6		$	(2.0	)	$	(6.0	)	$	(38.3	)
Per Basic Limited Partner Unit(2)	$	(0.06	)	$	(0.16	)	$	(0.39	)	$	(0.67	)
Per Diluted Limited Partner Unit(2)	$	(0.06	)	$	(0.16	)	$	(0.38	)	$	(0.66	)

Note: Figures may not sum due to rounding.

(1)

During the first quarter of 2006, we adopted SFAS No. 123(R)(revised) “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 effect adjustment represents a decrease to 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.

(2)

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 $0.16 for the third quarter of 2006, $0.13 for the third quarter of 2005, $0.31 for the first nine months of 2006 and $0.12 for the first nine months of 2005. This impact is included as a selected item impacting income per limited partner unit.

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The following table presents certain selected financial information by segment for the third quarter reporting periods:

	Three Months Ended						Three Months Ended
	September 30, 2006						September 30, 2005
				Gathering,						Gathering,
				Marketing,						Marketing,
				Terminalling &						Terminalling &
	Pipeline			Storage			Pipeline			Storage
	Operations			Operations			Operations			Operations(4)
	(in millions)						(in millions)
Revenues(1)	$	281.5		$	4,284.8		$	303.3		$	8,395.8
Purchases and related costs		(167.8	)		(4,136.7	)		(206.7	)		(8,292.7	)
Field operating costs (excluding LTIP charge)		(47.2	)		(43.4	)		(37.0	)		(30.4	)
LTIP charge – operations		(0.4	)		(0.6	)		(0.3	)		(0.6	)
Segment G&A expenses (excluding LTIP charge)(2)		(9.8	)		(13.9	)		(10.2	)		(10.5	)
LTIP charge – general and administrative		(4.1	)		(5.2	)		(3.4	)		(2.4	)
Segment profit	$	52.2		$	85.0		$	45.7		$	59.2
SFAS 133 mark-to-market impact(3)	$	-		$	17.9		$	-		$	6.3
Maintenance capital	$	5.3		$	2.9		$	2.9		$	1.3

(1)	Includes inter-segment amounts. We have adopted EITF 04-13, which impacts the comparability of our revenues, effective April 1, 2006. Revenues for the three months ended September 30, 2005 include buy/sell transactions of $52.2 million and $4,442.8 million in the Pipeline segment and Gathering, Marketing, Terminalling & Storage segment, respectively.
(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)	Amounts related to SFAS 133 are included in revenues and impact segment profit. The SFAS 133 mark-to-market adjustment is primarily based upon crude oil prices (and to a lesser extent, other product 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 substantially offset by physical positions in future periods.
(4)	Gains/losses on foreign currency revaluation are included in the Gathering, Marketing, Terminalling & Storage segment.

Excluding selected items impacting comparability in both periods, adjusted segment profit from pipeline operations in the third quarter of 2006 was $56.7 million versus $49.4 million for the third quarter of 2005 on average daily volumes of 2.1 million barrels per day versus 1.8 million barrels per day. The improvement in pipeline segment profit stems from new contracts on the Basin and Capline systems and acquisitions made subsequent to the third quarter of 2005. Adjusted segment profit from gathering, marketing, terminalling and storage operations for the third quarter of 2006 was $72.9 million, an increase of approximately 27% over the corresponding period in 2005. Gathering, marketing, terminalling and storage segment performance was predominantly driven by favorable market conditions, successful execution of our risk management strategies and contributions from recent acquisitions.

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The following table presents certain selected financial information by segment for the first nine-month reporting periods:

	Nine Months Ended						Nine Months Ended
	September 30, 2006						September 30, 2005
				Gathering,						Gathering,
				Marketing,						Marketing,
				Terminalling &						Terminalling &
	Pipeline			Storage			Pipeline			Storage
	Operations			Operations			Operations			Operations(4)
	(in millions)						(in millions)
Revenues(1)	$	841.4		$	17,328.7		$	811.1		$	21,753.0
Purchases and related costs		(522.0	)		(16,945.9	)		(526.2	)		(21,496.8	)
Field operating costs (excluding LTIP charge)		(137.1	)		(120.7	)		(108.8	)		(89.0	)
LTIP charge – operations		(1.0	)		(1.7	)		(0.7	)		(1.5	)
Segment G&A expenses (excluding LTIP charge)(2)		(27.1	)		(40.7	)		(29.6	)		(30.5	)
LTIP charge – general and administrative		(10.9	)		(13.5	)		(8.7	)		(6.0	)
Segment profit	$	143.3		$	206.2		$	137.1		$	129.2
SFAS 133 mark-to-market impact(3)	$	-		$	14.8		$	-		$	(20.0	)
Maintenance capital	$	11.5		$	5.8		$	8.2		$	4.0

(1)	Includes inter-segment amounts. We have adopted EITF 04-13, which impacts the comparability of our revenues, effective April 1, 2006. Revenues include buy/sell transactions in the nine months ended September 30, 2006 of $45.3 million and $4,717.7 million and in the nine months ended September 30, 2005 of $125.8 million and $11,630.0 million in the Pipeline segment and Gathering, Marketing, Terminalling & Storage segment, respectively.
(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)	Amounts related to SFAS 133 are included in revenues and impact segment profit. The SFAS 133 mark-to-market adjustment is primarily based upon crude oil prices (and to a lesser extent, other product 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 substantially offset by physical positions in future periods.
(4)	Gains/losses on foreign currency revaluation are included in the Gathering, Marketing, Terminalling & Storage segment.

The Partnership’s basic weighted average units outstanding for the third quarter of 2006 totaled 79.9 million (80.8 million diluted) as compared to 68.0 million (69.4 million diluted) in last year’s third quarter. At September 30, 2006, the Partnership had approximately 81.0 million units outstanding, long-term debt of $1.2 billion and a long-term debt to total capitalization ratio of approximately 39%.

On October 24, 2006, the board of directors approved and the Partnership declared a cash distribution of $0.75 per unit ($3.00 per unit on an annualized basis) on its outstanding limited partner units. The distribution will be payable on November 14, 2006, to holders of record of such units at the close of business on November 3, 2006. The distribution represents an increase of 11.1% over the November 2005 distribution and 3.4% over the August 2006 distribution. This distribution marks the Partnership’s tenth consecutive quarterly distribution increase and the seventeenth increase in the last twenty-three quarters.

The Partnership today furnished a current report on Form 8-K, which included material in this press release and financial and operational guidance for the fourth quarter of 2006. A copy of the Form 8-K is available on the Partnership’s website at www.paalp.com.

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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 results of operations or cash provided by 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 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 flow 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 page.

Conference Call

The Partnership will host a conference call to discuss the results and other forward-looking items on Thursday, November 2, 2006. Specific items to be addressed in this call include:

1.	A review of the Partnership’s third quarter performance;
2.	A status report on major expansion projects and recent acquisition activity;
3.	A discussion of capitalization and liquidity;
4.	A review of financial and operating guidance for the fourth quarter of 2006; and
5.	Comments regarding the Partnership’s outlook for the future.

The call will begin at 9:00 AM (Central). To participate in the call, please dial 877-709-8150, or, for international callers, 201-689-8354 at approximately 8:55 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 acct #232 and replay #217019. The replay will be available beginning Thursday, November 2, 2006, at approximately 1:00 PM (Central) and continue until 10:59 PM (Central) Monday, November 6, 2006.

Plains All American Pipeline, L.P. is engaged in interstate and intrastate crude oil transportation and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and

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other petroleum products, in the United States and Canada. Through its 50% ownership in PAA/Vulcan Gas Storage LLC, the Partnership is also engaged in the development and operation of natural gas storage facilities. The Partnership’s common units are traded on the New York Stock Exchange under the symbol “PAA.” The Partnership is headquartered in Houston, Texas.

Investor Notice

Plains All American Pipeline, L.P. has filed with the Securities and Exchange Commission a registration statement on Form S-4 (as the same may be supplemented or amended, Registration No. 333-135712) containing the joint proxy statement/prospectus of Plains All American Pipeline, L.P. and Pacific Energy Partners, L.P. and other documents in relation to the merger between Plains All American Pipeline, L.P. and Pacific Energy Partners, L.P. Investors and security holders are urged to read carefully these documents because they contain important information regarding Plains All American Pipeline, L.P., Pacific Energy Partners, L.P. and the merger. A definitive joint proxy statement/prospectus has been sent to security holders of Plains All American Pipeline, L.P. and Pacific Energy Partners, L.P. seeking their approval of the transactions contemplated by the merger agreement. Investors and security holders may obtain a free copy of the definitive joint proxy statement/prospectus and other documents containing information about Plains All American Pipeline, L.P. and Pacific Energy Partners, L.P., without charge, at the SEC’s website at www.sec.gov. Copies of the definitive joint proxy statement/prospectus and the SEC filings that are incorporated by reference in the definitive joint proxy statement/prospectus may also be obtained free of charge by directing a request to the respective partnerships as follows: Information regarding Plains All American Pipeline can be obtained by contacting its investor relations department at 713-646-4100 or by accessing its website at www.paalp.com, and information regarding Pacific Energy Partners can be obtained by contacting its investor relations department at 562-728-2871 or by accessing its website at www.PacificEnergy.com.

Plains All American Pipeline, L.P. and Pacific Energy Partners, L.P. and the officers and directors of the respective general partners of Plains All American Pipeline, L.P. and Pacific Energy Partners, L.P. may be deemed to be participants in the solicitation of proxies from their security holders. Information about these persons can be found in Plains All American Pipeline, L.P.’s and Pacific Energy Partners, L.P.’s respective Annual Reports on Form 10-K and Form 10-K/A filed with the SEC, and additional information about such persons may be obtained from the joint proxy statement/prospectus.

This document shall not constitute an offer to sell or the solicitation of an offer to buy any securities, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of the Securities Act of 1933, as amended.

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: our failure to successfully integrate the respective business operations upon completion of the merger with Pacific or our failure to successfully integrate any future acquisitions; the failure to realize the anticipated cost savings, synergies and other benefits of the proposed 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 system; declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by us and third party shippers; the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate; demand for natural gas or various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements; fluctuations in refinery capacity in areas supplied by our main lines; 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

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equity financing on satisfactory terms; 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, 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; shortages or cost increases of power supplies, materials or labor; weather interference with business operations or project construction; general economic, market or business conditions; risks related to the development and operation of natural gas storage facilities and other factors and uncertainties inherent in the marketing, transportation, terminalling, gathering and storage of crude oil and liquefied petroleum gas 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						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
REVENUES(1)	$	4,525.8		$	8,664.4		$	18,053.6		$	22,463.6
COSTS AND EXPENSES
Purchases and related costs		4,264.0			8,464.7			17,351.4			21,922.5
Field operating costs		91.6			68.3			260.5			200.0
General and administrative expenses		33.0			26.5			92.2			74.8
Depreciation and amortization		24.2			20.0			67.1			58.1
Total costs and expenses		4,412.8			8,579.5			17,771.2			22,255.4
OPERATING INCOME		113.0			84.9			282.4			208.2
OTHER INCOME/(EXPENSE)
Equity earnings in PAA/Vulcan Gas Storage, LLC		1.3			-			2.2			-
Interest expense		(19.2	)		(15.6	)		(52.5	)		(44.4	)
Interest income and other income (expense), net		0.3			(0.3	)		0.7			0.3
Income before cumulative effect of change in accounting principle		95.4			69.0			232.8			164.1
Cumulative effect of change in accounting principle		-			-			6.3			-
NET INCOME	$	95.4		$	69.0		$	239.1		$	164.1
NET INCOME – LIMITED PARTNERS	$	84.6		$	63.9		$	212.7		$	150.8
NET INCOME – GENERAL PARTNER	$	10.8		$	5.1		$	26.4		$	13.3
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.90		$	0.81		$	2.37		$	2.11
Cumulative effect of change in accounting principle		-			-			0.08			-
Basic net income per limited partner unit	$	0.90		$	0.81		$	2.45		$	2.11
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.89		$	0.79		$	2.35		$	2.07
Cumulative effect of change in accounting principle		-			-			0.08			-
Diluted net income per limited partner unit	$	0.89		$	0.79		$	2.43		$	2.07
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING		79.9			68.0			77.0			67.8
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING		80.8			69.4			77.8			68.9

(1) Revenues include buy/sell transactions of $4.5 billion in the three months ended September 30, 2005 and $4.8 billion and $11.8 billion in the nine months ended September 30, 2006 and 2005, respectively.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

	Three Months Ended				Nine Months Ended
OPERATING DATA (in thousands)(1)	September 30,				September 30,
Average Daily Volumes (barrels)	2006		2005		2006		2005
Pipeline activities:
Tariff activities
All American		50		51		49		51
Basin		324		290		323		283
BOA / CAM		168		-		57		-
Capline		183		129		149		144
Cushing to Broome		69		79		73		62
North Dakota/Trenton		94		85		88		73
West Texas/New Mexico Area Systems(2)		416		428		445		422
Canada		249		250		247		255
Other		486		437		464		424
Pipeline margin activities		93		65		89		69
Pipeline activities total		2,132		1,814		1,984		1,783
GMT&S activities:
Crude oil lease gathering		650		598		639		616
LPG sales and third party processing		55		41		60		50
Waterborne foreign crude imported		80		61		59		60
GMT&S activities total		785		700		758		726

(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.

CONDENSED CONSOLIDATED BALANCE SHEET DATA

(in millions)

	September 30,		December 31,
	2006		2005
ASSETS
Current assets	$	2,992.2	$	1,805.2
Property and equipment, net		2,359.0		1,857.2
Pipeline linefill in owned assets		204.1		180.2
Inventory in third party assets		77.0		71.5
Investment in PAA/Vulcan Gas Storage, LLC		125.7		113.5
Goodwill		183.3		47.4
Other long-term assets, net		106.6		45.3
Total assets	$	6,047.9	$	4,120.3
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	2,941.2	$	1,793.3
Long-term debt under credit facilities and other		3.6		4.7
Senior notes, net of unamortized discount		1,196.8		947.0
Other long-term liabilities and deferred credits		66.9		44.6
Total liabilities		4,208.5		2,789.6
Partners’ capital		1,839.4		1,330.7
Total liabilities and partners’ capital	$	6,047.9	$	4,120.3

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

FINANCIAL SUMMARY (unaudited)

COMPUTATION OF BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT

(in millions, except per unit data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Numerator for basic and diluted earnings per limited partner unit:
Net income	$	95.4		$	69.0		$	239.1		$	164.1
Less: General partner’s incentive distribution paid		(9.1	)		(3.8	)		(22.1	)		(10.2	)
Subtotal		86.3			65.2			217.0			153.9
General partner 2% ownership		(1.7	)		(1.3	)		(4.3	)		(3.1	)
Net income available to limited partners		84.6			63.9			212.7			150.8
Pro forma additional general partner’s distribution(1)		(12.6	)		(9.1	)		(23.8	)		(8.0	)
Net income available for limited partners under EITF 03-06		72.0			54.8			188.9			142.8
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	$	72.0		$	54.8		$	182.7		$	142.8
Denominator:
Basic weighted average number of limited partner units outstanding		79.9			68.0			77.0			67.8
Effect of dilutive securities
Weighted average 2005 Long-Term Incentive Plan (“LTIP”) units		0.9			1.4			0.8			1.1
Diluted weighted average number of limited partner units outstanding		80.8			69.4			77.8			68.9
Basic net income per limited partner unit before cumulative effect of change in accounting principle(1)	$	0.90		$	0.81		$	2.37		$	2.11
Cumulative effect of change in accounting principle per limited partner unit		-			-			0.08			-
Basic net income per limited partner unit	$	0.90		$	0.81		$	2.45		$	2.11
Diluted net income per limited partner unit before cumulative effect of change in accounting principle(1)	$	0.89		$	0.79		$	2.35		$	2.07
Cumulative effect of change in accounting principle per limited partner unit		-			-			0.08			-
Diluted net income per limited partner unit	$	0.89		$	0.79		$	2.43		$	2.07

⁽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 $0.16 and $0.13 for the three months ended and $0.31 and $0.12 for the nine months ended September 30, 2006 and 2005, respectively.

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FINANCIAL DATA RECONCILIATIONS

(in millions, except per unit data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Earnings before interest, taxes, depreciation and amortization (“EBITDA”)
Net income reconciliation
EBITDA	$	138.8		$	104.6		$	358.7		$	266.6
Depreciation and amortization		(24.2	)		(20.0	)		(67.1	)		(58.1	)
Earnings before interest and taxes (“EBIT”)		114.6			84.6			291.6			208.5
Interest expense		(19.2	)		(15.6	)		(52.5	)		(44.4	)
Net income	$	95.4		$	69.0		$	239.1		$	164.1
Cash flow from operating activities reconciliation
EBITDA	$	138.8		$	104.6		$	358.7		$	266.6
Interest expense		(19.2	)		(15.6	)		(52.5	)		(44.4	)
Net change in assets and liabilities, net of acquisitions		349.2			(87.2	)		(495.2	)		(709.4	)
Other items to reconcile to cash flows from operating activities:
Equity earnings in PAA/Vulcan Gas Storage, LLC		(1.3	)		-			(2.2	)		-
Net cash paid for terminated interest rate hedging instruments		-			-			-			(0.8	)
Net (gain)/loss on foreign currency revaluation		0.3			1.4			2.1			0.4
SFAS 133 mark-to-market adjustment		(17.9	)		(6.3	)		(14.8	)		20.0
Cumulative effect of change in accounting principle		-			-			(6.3	)		-
LTIP charge		10.3			6.7			27.1			16.9
Non-cash amortization of terminated interest rate hedging instruments		0.4			0.4			1.2			1.2
Net cash provided by/(used in) operating activities	$	460.6		$	4.0		$	(181.9	)	$	(449.5	)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Funds flow from operations (“FFO”)
Net Income	$	95.4		$	69.0		$	239.1		$	164.1
Equity earnings in PAA/Vulcan Gas Storage, LLC		(1.3	)		-			(2.2	)		-
Depreciation and amortization		24.2			20.0			67.1			58.1
Non-cash amortization of terminated interest rate hedging instruments		0.4			0.4			1.2			1.2
FFO		118.7			89.4			305.2			223.4
Maintenance capital expenditures		(8.2	)		(4.2	)		(17.3	)		(12.2	)
FFO after maintenance capital expenditures	$	110.5		$	85.2		$	287.9		$	211.2

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Page 12

FINANCIAL DATA RECONCILIATIONS

(in millions, except per unit data) (continued)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2006			2005			2006			2005
Selected items impacting comparability
LTIP charge	$	(10.3	)	$	(6.7	)	$	(27.1	)	$	(16.9	)
Cumulative effect of change in accounting principle – LTIP		-			-			6.3			-
Loss on foreign currency revaluation		-			(1.6	)		-			(1.4	)
SFAS 133 mark-to-market adjustment		17.9			6.3			14.8			(20.0	)
Selected items impacting comparability		7.6			(2.0	)		(6.0	)		(38.3	)
GP 2% portion of selected items impacting comparability		(0.2	)		-			0.1			0.8
LP 98% portion of selected items impacting comparability	$	7.4		$	(2.0	)	$	(5.9	)	$	(37.5	)
Impact to basic net income per limited partner unit(1)	$	(0.06	)	$	(0.16	)	$	(0.39	)	$	(0.67	)
Impact to diluted net income per limited partner unit(1)	$	(0.06	)	$	(0.16	)	$	(0.38	)	$	(0.66	)

⁽¹⁾ Includes the application of EITF 03-06, which negatively impacted basic and diluted earnings per limited partner unit by approximately $0.16 and $0.13 for the three months ended and $0.31 and $0.12 for the nine months ended September 30, 2006 and 2005, respectively.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006		2005
Net income and earnings per limited partner unit excluding selected items impacting comparability
Net income	$	95.4		$	69.0	$	239.1	$	164.1
Selected items impacting comparability		(7.6	)		2.0		6.0		38.3
Adjusted net income	$	87.8		$	71.0	$	245.1	$	202.4
Net income available for limited partners under EITF 03-06	$	72.0		$	54.8	$	188.9	$	142.8
Limited partners 98% of selected items impacting comparability		(7.4	)		2.0		5.9		37.5
Pro forma additional general partner distribution under EITF 03-06		12.6			9.1		23.8		8.0
Adjusted limited partners net income	$	77.2		$	65.9	$	218.6	$	188.3
Adjusted basic net income per limited partner unit	$	0.96		$	0.97	$	2.84	$	2.78
Adjusted diluted net income per limited partner unit	$	0.95		$	0.95	$	2.81	$	2.73
Basic weighted average units outstanding		79.9			68.0		77.0		67.8
Diluted weighted average units outstanding		80.8			69.4		77.8		68.9

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Page 13

FINANCIAL DATA RECONCILIATIONS

(in millions, except per unit data) (continued)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006		2005
EBITDA excluding selected items impacting comparability
EBITDA	$	138.8		$	104.6	$	358.7	$	266.6
Selected items impacting comparability		(7.6	)		2.0		6.0		38.3
Adjusted EBITDA	$	131.2		$	106.6	$	364.7	$	304.9

	Three Months Ended					Nine Months Ended
	September 30, 2006					September 30, 2006
	Pipeline		GMT&S			Pipeline		GMT&S
2006 Segment profit excluding selected items impacting comparability
Reported segment profit	$	52.2	$	85.0		$	143.3	$	206.2
Selected items impacting comparability of segment profit:
LTIP charge		4.5		5.8			11.9		15.2
SFAS 133 mark-to-market adjustment		-		(17.9	)		-		(14.8	)
Segment profit excluding selected items impacting comparability	$	56.7	$	72.9		$	155.2	$	206.6

	Three Months Ended					Nine Months Ended
	September 30, 2005					September 30, 2005
	Pipeline		GMT&S			Pipeline		GMT&S
2005 Segment profit excluding selected items impacting comparability
Reported segment profit	$	45.7	$	59.2		$	137.1	$	129.2
Selected items impacting comparability of segment profit:
LTIP charge		3.7		3.0			9.4		7.5
Loss on foreign currency revaluation		-		1.6			-		1.4
SFAS 133 mark-to-market adjustment		-		(6.3	)		-		20.0
Segment profit excluding selected items impacting comparability	$	49.4	$	57.5		$	146.5	$	158.1

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