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)—May 3, 2006

Plains All American Pipeline, L.P.

(Exact name of registrant as specified in its charter)

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

333 Clay Street, Suite 1600, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

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

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

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

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

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

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

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

Item 9.01.  Financial Statements and Exhibits

(d)   Exhibit 99.1—Press Release dated May 3, 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 first 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 detail guidance for financial performance for the second quarter of calendar 2006 and modifying certain aspects of our previous guidance for financial performance for the full year of calendar 2006 (which supersedes guidance in our 8-K furnished on February 23, 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.

Disclosure of Second Quarter 2006 Estimates; Update of Full Year 2006 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 11 below, we reconcile EBITDA and EBIT to net income for the guidance periods presented. However, it is impractical to reconcile EBIT and EBITDA to cash flows from operating activities for forecasted periods. We also encourage you to visit our website at www.paalp.com, and 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, revaluations of foreign currency, cumulative effect of a change in accounting principle and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments) on EBITDA, Net Income and Net Income per Limited Partner Unit.

The following guidance for the three months ending June 30, 2006 and the six months and twelve months ending December 31, 2006 are 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 May 2, 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(1)
				Three				Six				Twelve
	Three			Months				Months				Months
	Months			Ending				Ending				Ending
	Ended			June 30,				December 31,				December 31,
	March 31,			2006				2006				2006
	2006			Low		High		Low		High		Low		High
Pipeline
Net revenues		$ 96.4		$ 101.0		$ 103.6		$ 209.9		$ 212.7		$ 407.3		$ 412.7
Field operating costs		(45.1	)	(48.2	)	(47.6	)	(93.2	)	(92.0	)	(186.5	)	(184.7	)
General and administrative expenses		(13.3	)	(11.4	)	(11.2	)	(23.4	)	(23.0	)	(48.1	)	(47.5	)
		38.0		41.4		44.8		93.3		97.7		172.7		180.5
Gathering, Marketing, Terminalling & Storage
Net revenues		111.6		97.9		103.4		204.2		217.8		413.7		432.8
Field operating costs		(37.2	)	(39.0	)	(38.4	)	(79.3	)	(78.1	)	(155.5	)	(153.7	)
General and administrative expenses		(18.5	)	(19.2	)	(18.9	)	(38.7	)	(38.1	)	(76.4	)	(75.5	)
		55.9		39.7		46.1		86.2		101.6		181.8		203.6
Segment Profit		93.9		81.1		90.9		179.5		199.3		354.5		384.1
Depreciation and amortization expense		(21.6	)	(23.1	)	(22.7	)	(48.0	)	(47.2	)	(92.7	)	(91.5	)
Interest expense		(15.3	)	(18.6	)	(17.8	)	(37.3	)	(35.7	)	(71.2	)	(68.8	)
Equity earnings (Loss) in PAA / Vulcan Gas Storage, LLC		(0.2	)	0.6		0.8		1.9		2.1		2.3		2.7
Other Income (Expense)		0.3		—		—		—		—		0.3		0.3
Income Before Cumulative Effect of Change in Accounting Principle		57.1		40.0		51.2		96.1		118.5		193.2		226.8
Cumulative Effect of Change in Accounting Principle		6.3		—		—		—		—		6.3		6.3
Net Income		$ 63.4		$ 40.0		$ 51.2		$ 96.1		$ 118.5		$ 199.5		$ 233.1
Net Income to Limited Partners		$ 56.7		$ 32.0		$ 43.0		$ 79.8		$ 101.7		$ 168.5		$ 201.4
Basic Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		74.0		77.0		77.0		77.3		77.3		76.4		76.4
Net Income Per Unit		$ 0.73		$ 0.42		$ 0.56		$ 1.03		$ 1.32		$ 2.20		$ 2.63
Diluted Net Income Per Limited Partner Unit
Weighted Average Units Outstanding		75.7		78.7		78.7		79.0		79.0		78.1		78.1
Net Income Per Unit		$ 0.71		$ 0.41		$ 0.55		$ 1.01		$ 1.29		$ 2.16		$ 2.58
EBIT		$ 78.7		$ 58.6		$ 69.0		$ 133.4		$ 154.2		$ 270.7		$ 301.9
EBITDA		$ 100.3		$ 81.7		$ 91.7		$ 181.4		$ 201.4		$ 363.4		$ 393.4
Selected Items Impacting Comparability
LTIP charge		$ (10.6	)	$ (8.3	)	$ (8.3	)	$ (17.4	)	$ (17.4	)	$ (36.3	)	$ (36.3	)
Cumulative Effect of Change in Accounting Principle		6.3		—		—		—		—		6.3		6.3
SFAS 133 Mark-to-Market Adjustment		(0.7	)	—		—		—		—		(0.7	)	(0.7	)
Gain (loss) on Foreign Currency Revaluation		(0.9	)	—		—		—		—		(0.9	)	(0.9	)
		$ (5.9	)	$ (8.3	)	$ (8.3	)	$ (17.4	)	$ (17.4	)	$ (31.6	)	$ (31.6	)
Excluding Selected Items Impacting Comparability
Adjusted EBITDA		$ 106.2		$ 90.0		$ 100.0		$ 198.8		$ 218.8		$ 395.0		$ 425.0
Adjusted Net Income		$ 69.3		$ 48.3		$ 59.5		$ 113.5		$ 135.9		$ 231.1		$ 264.7
Adjusted Basic Net Income per Limited Partner Unit		$ 0.84		$ 0.52		$ 0.66		$ 1.25		$ 1.54		$ 2.61		$ 3.04
Adjusted Diluted Net Income per Limited Partner Unit		$ 0.82		$ 0.51		$ 0.65		$ 1.24		$ 1.50		$ 2.55		$ 2.98

(1)    The projected average foreign exchange rate is $1.15 CAD to $1 USD.

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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
Bbl/d	Barrel 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 end-user refineries, field declines and other external factors beyond our control. Actual segment profit could vary materially depending on the level of volumes transported.

For the three months ending June 30, 2006 projected volumes incorporate assumptions with respect to 1) additional throughput agreements and expected higher seasonal demand volumes on Capline Pipeline, and 2) higher Canadian volumes primarily due to the purchase of the remaining interest in Cactus Lake Pipeline. Volumes for the remainder of the year are impacted by a combination of anticipated seasonal demand, recovery of certain volumes impacted by last year’s hurricanes, and natural field declines.

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

	Calendar 2006
	Actual		Guidance(3)
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	March 31		June 30			December 31			December 31
Average Daily Volumes (000's Bbl/d)
All American		44		50			48			47
Basin		314		225			266			267
Capline		86		175			160			146
Cushing to Broome		70		80			80			77
North Dakota/Trenton		82		92			91			89
West Texas / New Mexico area systems(1)		442		409			388			407
Canada(2)		239		262			264			258
Other		537		547			543			539
		1,814		1,840			1,840			1,830
Average Segment Profit ($/Bbl)
As Reported/Estimated		$ 0.233		$ 0.257	(3)		$ 0.282	(3)		$ 0.264	(3)
Excluding Selected Items Impacting Comparability		$ 0.263		$ 0.280	(3)		$ 0.306	(3)		$ 0.289	(3)

(1)    The aggregate of 11 systems in the West Texas / New Mexico area.

(2)    The aggregate of 8 systems.

(3)    Mid-point of estimate.

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Segment profit is forecast using the volume assumptions in the table above, priced at tariff rates currently received, with adjustments where appropriate for estimated escalation in certain rates as allowed by contractual terms, 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 segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 25% of total pipeline net revenues.

Volume Sensitivity Analysis
			% of			Incr (Decr)
	Incr (Decr)		System			in Annualized
System	in Volume		Total			Segment Profit
	(Bbls/d)					(in millions)
All American		5,000		11	%		$ 3.6
Basin		20,000		7	%		1.4
Capline		10,000		7	%		1.3

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 months ending June 30, 2006 reflect an expected continuation of the current contango market and favorable market conditions, although not quite as favorable as market conditions in the first quarter. Operating results for the remaining six months of 2006 reflect the expectation that the market structure will be more favorable than market conditions for 2003 and 2004, but not as favorable as those experienced throughout 2005, which were considered very favorable relative to our asset base and business model.

	Calendar 2006
	Actual		Guidance(1)
	Three Months		Three Months			Six Months			Twelve Months
	Ended		Ending			Ending			Ending
	March 31		June 30			December 31			December 31
Average Daily Volumes (000’s Bbl/d)
Crude Oil Lease Gathering		615		635			651			637
LPG		84		58			93			82
		699		693			744			719
Segment Profit per Barrel
As Reported/Estimated		$ 0.89		$ 0.68	(1)		$ 0.69	(1)		$ 0.73	(1)
Excluding Selected Items Impacting Comparability		$ 1.01		$ 0.75	(1)		$ 0.75	(1)		$ 0.82	(1)

(1)Mid-point of estimate.

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. The forecast also includes the incremental profits from recently completed acquisitions. 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 calendar 2006, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by approximately $4.5 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by approximately $2.6 million on an annualized basis.

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 property and equipment) to 40 years (for certain pipelines, crude oil terminals and facilities).

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5.Foreign Currency Revaluations and 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 foreign currency revaluations and 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 foreign currency revaluations and 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 material acquisition that may be made after the date hereof. Capital expenditures for expansion projects are forecast to be approximately $250 million during calendar 2006 of which $45 million was incurred in the first quarter. Following are some of the more notable projects to be undertaken in 2006 and the estimated expenditures for the year.

	Calendar 2006
	(in millions)
Expansion Capital
·  St. James, Louisiana storage facility		$ 60
·  Kerrobert tankage and pumps		45
·  Spraberry System expansion		20
·  High Prairie truck and rail terminals		18
·  East Texas/Louisiana tankage		16
·  Wichita Falls tankage		11
·  Midale/Regina truck terminal		11
·  Truck trailers		11
·  Other Projects		58
		250
Maintenance Capital		23
Total Projected Capital Expenditures		$ 273

7.Capital Structure.   The guidance is based on our capital structure as of March 31, 2006, adjusted for the sale of 1.2 million common units in April 2006.

8.Interest Expense.   Debt balances are projected based on estimated cash flows, current distribution rates, 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.

Calendar 2006 interest expense is expected to be between $68.8 million and $71.2 million, assuming an average long-term debt balance of approximately $1.2 billion and an all-in average rate of approximately 6.0%. 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 margin deposits). At March 31, 2006, 100% of our long-term debt balance was fixed at an average interest rate of 6.0%. The amortization of

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deferred amounts associated with terminated interest rate hedges results in a non-cash component to interest expense of approximately $400,000 per quarter through September 2006, decreasing to approximately $100,000 per quarter thereafter until fully amortized over the next ten years.

Interest expense does not include interest on borrowings for contango inventory. We treat these costs as carrying costs of crude oil and include it as part of the purchase price of crude oil.

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.

	Guidance (in millions)
	Three Months Ending						Six Months Ending						Twelve Months Ending
	June 30, 2006						December 31, 2006						December 31, 2006
	Low			High			Low			High			Low			High
Numerator for basic and diluted earnings per limited partner unit:
Net Income		$ 40.0			$ 51.2			$ 96.1			$ 118.5			$ 199.5			$ 233.1
Less:
General partner’s incentive distribution		(7.3	)		(7.3	)		(14.7	)		(14.7	)		(27.6	)		(27.6	)
		32.7			43.9			81.4			103.8			171.9			205.5
General partner 2% ownership		(0.7	)		(0.9	)		(1.6	)		(2.1	)		(3.4	)		(4.1	)
Net income available to limited partners		32.0			43.0			79.8			101.7			168.5			201.4
Pro forma additional general partner’s incentive distribution		—			—			—			—			—			—
Net Income available for limited partners under EITF 03-06		$ 32.0			$ 43.0			$ 79.8			$ 101.7			$ 168.5			$201.4
Denominator:
Denominator for basic earnings per limited partner unit- weighted average number of limited partner units		77.0			77.0			77.3			77.3			76.4			76.4
Effect of dilutive securities:
Weighted average LTIP units		1.7			1.7			1.7			1.7			1.7			1.7
Denominator for diluted earnings per limited partner unit-weighted average number of limited partner units		78.7			78.7			79.0			79.0			78.1			78.1
Basic net income per limited partner unit		$ 0.42			$ 0.56			$ 1.03			$ 1.32			$ 2.20			$ 2.63
Diluted net income per limited partner unit		$ 0.41			$ 0.55			$ 1.01			$ 1.29			$ 2.16			$ 2.58

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

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the amount of the general partner’s incentive distribution. Based on our current annualized distribution rate of $2.83 per unit, our general partner’s distribution is forecast to be approximately $33.9 million annually, of which $29.4 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 $2.83 per unit decreases net income available for limited partners by approximately $3.7 million ($0.05 per unit) on an annualized basis.

10.Long-term Incentive Plans.   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. The majority of phantom unit grants outstanding under our 1998 and 2005 Long-Term Incentive Plans contain vesting criteria that are based on a combination of performance benchmarks and service period. The phantom units under the 2005 plan primarily vest in various percentages on the later of 1) May 2007, May 2009, and May 2010, or 2) achievement of annualized distribution levels of $2.60, $2.80, $3.00, respectively, and for certain grants, $3.10 per unit. The majority of the phantom units have a final service period vesting in 2011. In addition to exceeding the distribution level of $2.80, it has been deemed probable that the $3.10 distribution level will be achieved. Accordingly, guidance includes, for phantom units tied to performance levels of $3.10 or less, an accrual over the corresponding service period. For 2006, the guidance includes approximately $36.3 million of principally non-cash expense associated with these phantom units. The earliest significant vesting event for outstanding grants will occur in 2007.

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, and will also be increased if a determination is made that achievement of any of the remaining performance thresholds is probable. Therefore, market variables could cause actual net income to differ materially from our projections.

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

	Guidance
	Three Months Ending						Six Months Ending						Twelve Months Ending
	June 30, 2006						December 31, 2006						December 31, 2006
	Low			High			Low			High			Low			High
	(in millions)
Reconciliation to Net Income
EBITDA		$ 81.7			$ 91.7			$ 181.4			$ 201.4			$ 363.4			$ 393.4
Depreciation and amortization		(23.1	)		(22.7	)		(48.0	)		(47.2	)		(92.7	)		(91.5	)
EBIT		58.6			69.0			133.4			154.2			270.7			301.9
Interest expense		(18.6	)		(17.8	)		(37.3	)		(35.7	)		(71.2	)		(68.8	)
Net Income		$ 40.0			$ 51.2			$ 96.1			$ 118.5			$ 199.5			$ 233.1

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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:

·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 transmission 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;

·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 rates of 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;

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·weather interference with business operations or project construction;

·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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned 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: May 3, 2006	By:	/s/ PHIL KRAMER
		Name:	Phil Kramer
		Title:	Executive Vice President and Chief Financial Officer

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EX-99.1

Exhibit 99.1

Contacts:	Phillip D. Kramer	Brad A. Thielemann
	Executive VP and CFO	Manager, Special Projects
	713/646-4560—800/564-3036	713/646-4222—800/564-3036

FOR IMMEDIATE RELEASE

Plains All American Pipeline, L.P. Reports
Strong Financial Results for First Quarter 2006—
Net Income Climbs 93%; Net Income Per Diluted Unit Up 65%;
EBITDA Up 51%

(Houston—May 3, 2006) Plains All American Pipeline, L.P. (NYSE: PAA) reported first quarter 2006 net income of $63.4 million, equivalent to $0.71 per diluted limited partner unit. These financial results represent increases of 93% and 65%, respectively, over net income of $32.8 million, or $0.43 per diluted limited partner unit, for the first quarter of 2005. As reported, earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the first quarter of 2006 were $100.3 million, an increase of 51% as compared with EBITDA of $66.5 million for the first quarter 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.

“Thus far in 2006, Plains All American has made significant progress toward accomplishing its goals for the year by delivering strong operating and financial results for the first-quarter and enhancing the visibility of its growth profile by completing five acquisitions for aggregate consideration of approximately $360 million,” said Greg Armstrong, Chairman and CEO of the Partnership.  “In addition, we remain on track to execute the largest program of internal growth projects in our history. The combination of these activities allowed us to raise our quarterly distribution to $0.7075 per unit, which marks our eighth consecutive quarterly distribution increase. As a result, we believe 2006 is off to a great start.”

Armstrong also noted that the Partnership continued to demonstrate a disciplined financial growth strategy as it pre-funded a significant portion of the recent acquisitions through the issuance of more than $150 million of new equity capital.

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 first quarter 2006 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $69.3 million, $0.82 per diluted unit and $106.2 million, respectively. By way of comparison, the Partnership’s first quarter 2005 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $49.2 million, $0.67 per diluted unit, and $82.9 million, respectively. On a comparable basis, first quarter 2006 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA increased 41%, 22% and 28%, respectively, over first quarter 2005.

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

	Three Months Ended March 31,
	2006			2005
	(in millions, except per unit data)
Long-Term Incentive Plan (“LTIP”) charge	$	(10.6	)	$	(2.2	)
Cumulative effect of change in accounting principle(1)	6.3			—
Gain/(Loss) on foreign currency revaluation	(0.9		)	(0.8		)
SFAS 133 mark-to-market adjustment	(0.7		)	(13.4		)
Total	$	(5.9	)	$	(16.4	)
Per Basic Limited Partner Unit(2)	$	(0.11	)	$	(0.24	)
Per Diluted Limited Partner Unit(2)	$	(0.11	)	$	(0.24	)

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)For the quarter ended March 31, 2006, the Partnership’s net income exceeded the cash distribution paid during such periods, which required 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”). This theoretical calculation 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 $0.04 for the first quarter of 2006.

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

	Three Months Ended March 31, 2006								Three Months Ended March 31, 2005
	Pipeline Operations				Gathering, Marketing, Terminalling & Storage Operations(4)				Pipeline Operations				Gathering, Marketing, Terminalling & Storage Operations(4)
	(in millions)								(in millions)
Revenues(1)		$	284.9			$	8,388.7			$	247.2			$	6,426.2
Purchases and related costs(1)		(188.5		)		(8,277.1		)		(151.7		)		(6,369.4		)
Field operating costs (excluding LTIP charge)		(44.8		)		(36.5		)		(34.0		)		(29.5		)
LTIP charge—operations		(0.3		)		(0.7		)		(0.1		)		(0.2		)
Segment G&A expenses (excluding LTIP charge)(2)		(8.7		)		(13.5		)		(10.1		)		(10.1		)
LTIP charge—general and administrative		(4.6		)		(5.0		)		(1.2		)		(0.7		)
Segment profit		$	38.0			$	55.9			$	50.1			$	16.3
SFAS 133 mark-to-market impact(3)		$	—			$	(0.7	)		$	—			$	(13.4	)
Maintenance capital		$	2.9			$	1.8			$	2.8			$	1.2

(1)Includes inter-segment amounts.

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(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 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 principally 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 first quarter of 2006 was $42.9 million, which was in-line with the high-end of our financial guidance range but was approximately $8.5 million lower than our adjusted segment profit of $51.4 million for the first quarter of 2005.  The decrease from 2005's first quarter adjusted segment profit is due primarily to an increase in operating expenses associated with an increase in personnel and related costs and utilities.  Utilities increased $4.1 million over the prior year period due to a variety of factors including  (1) the net impact of a general increase in electricity rates and power hedges and (2) a true up of prior and current accruals following receipt of final billing information upon expiration of an existing term arrangement with a significant electricity provider.   Adjusted segment profit from our gathering, marketing, terminalling and storage operations for the first quarter of 2006 was $63.2 million, up approximately 101% over the corresponding period in 2005 primarily as a result of an expanded asset base and continued favorable market conditions.

The Partnership’s basic weighted average units outstanding for the first quarter of 2006 totaled 74.0 million (75.7 million diluted) as compared to 67.5 million (68.2 million diluted) in last year’s first quarter. At March 31, 2006, the Partnership had approximately 76.1 million units outstanding, long-term debt of $951.5 million and a long-term debt to total capitalization ratio of approximately 40%. Adjusted for the completion of the recent equity offering, the Partnership had approximately 77.3 million units outstanding as of May 1, 2006.

On April 20, 2006, the Partnership declared a cash distribution of $0.7075 per unit ($2.83 per unit on an annualized basis) on its outstanding limited partner units. The distribution will be payable on May 15, 2006, to holders of record of such units at the close of business on May 5, 2006. The distribution represents an increase of 11.0% over the May 2005 distribution and 2.9% over the February 2006 distribution. This represents the 8th consecutive quarterly distribution increase and the 15th distribution increase for the Partnership in the last 21 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 second quarter and full year 2006. A copy of the Form 8-K is 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 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

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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 Wednesday, May 3, 2006. Specific items to be addressed in this call include:

1.A brief review of the Partnership’s first 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 second quarter and full year 2006; and

5.Comments regarding 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 acct # 232 and replay # 190857. The replay will be available beginning Wednesday, May 3, 2006, at approximately 1:00 PM (Central) and continue until 10:59 PM (Central) Monday, May 8, 2006.

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 success of our risk management activities; environmental liabilities or

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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 transmission 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; the impact of current and future laws, rulings and governmental regulations; the effects of competition; continued creditworthiness of, and performance by, counter parties; interruptions in service and fluctuations in rates of 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; 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 discussed in the Partnership’s filings with the Securities and Exchange Commission.

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 other petroleum products, in the United States and Canada. Through its 50% ownership in PAA/Vulcan Gas Storage LLC, the Partnership is 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.

# # #

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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 March 31,
	2006			2005
REVENUES	$	8,635.4		$	6,638.5
COSTS AND EXPENSES
Purchases and related costs	8,427.4			6,486.2
Field operating costs	82.3			63.8
General and administrative expenses	31.8			22.1
Depreciation and amortization	21.6			19.1
Total costs and expenses	8,563.1			6,591.2
OPERATING INCOME	72.3			47.3
OTHER INCOME/(EXPENSE)
Equity earnings (loss) in PAA/Vulcan Gas Storage, LLC	(0.2		)	—
Interest expense	(15.3		)	(14.6		)
Interest and other income (expense), net	0.3			0.1
Income before cumulative effect of change in accounting principle	57.1			32.8
Cumulative effect of change in accounting principle	6.3			—
NET INCOME	$	63.4		$	32.8
NET INCOME—LIMITED PARTNERS	$	56.7		$	29.3
NET INCOME—GENERAL PARTNER	$	6.7		$	3.5
BASIC NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.65		$	0.43
Cumulative effect of change in accounting principle	0.08			—
Basic net income per limited partner unit	$	0.73		$	0.43
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of change in accounting principle	$	0.63		$	0.43
Cumulative effect of change in accounting principle	0.08			—
Diluted net income per limited partner unit	$	0.71		$	0.43
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	74.0			67.5
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	75.7			68.2

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

OPERATING DATA (in thousands)(1)
Average Daily Volumes (barrels)
	Three Months Ended March 31,
	2006		2005
Pipeline activities:
Tariff activities
All American		44		54
Basin		314		277
Capline		86		160
Cushing to Broome		70		23
North Dakota/Trenton		82		61
West Texas/New Mexico Area Systems(2)		442		401
Canada		239		268
Other		446		410
Pipeline margin activities		91		75
Total		1,814		1,729
Crude oil lease gathering		615		622
LPG sales		84		84

(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)
	March 31,			December 31,
	2006			2005
ASSETS
Current assets		$	2,374.4		$	1,805.2
Property and equipment, net		1,899.5			1,857.2
Pipeline linefill in owned assets		180.1			180.2
Inventory in third party assets		71.9			71.5
Investment in PAA/Vulcan Gas Storage, LLC		113.3			113.5
Other long-term assets, net		94.5			92.7
Total Assets		$	4,733.7		$	4,120.3
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities		$	2,294.1		$	1,793.3
Long-term debt under credit facilities and other		4.4			4.7
Senior notes, net of unamortized discount		947.1			947.0
Other long-term liabilities and deferred credits		49.4			44.6
Total Liabilities		3,295.0			2,789.6
Partners’ capital		1,438.7			1,330.7
Total Liabilities and Partners’ Capital		$	4,733.7		$	4,120.3

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

COMPUTATION OF BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT
(in millions, except per unit data)
	Three months ended March 31,
	2006			2005
Numerator for basic and diluted earnings per limited partner unit:
Net income	$	63.4		$	32.8
Less: General partner’s incentive distribution paid	(5.5		)	(2.9		)
Subtotal	57.9			29.9
General partner 2% ownership	(1.2		)	(0.6		)
Net income available to limited partners	56.7			29.3
Pro forma additional general partner’s incentive distribution(1)	(2.9		)	—
Net income available for limited partners under EITF 03-06	53.8			29.3
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	$	47.6		$	29.3
Denominator:
Basic weighted average number of limited partner units outstanding	74.0			67.5
Effect of dilutive securities:
Weighted average 2005 Long-Term Incentive Plan (“LTIP”) units	1.7			0.7
Diluted weighted average number of limited partner units outstanding	75.7			68.2
Basic net income per limited partner unit before cumulative effect of change in accounting principle(1)	$	0.65		$	0.43
Cumulative effect of change in accounting principle per limited partner unit	0.08			—
Basic net income per limited partner unit	$	0.73		$	0.43
Diluted net income per limited partner unit before cumulative effect of change in accounting principle(1)	$	0.63		$	0.43
Cumulative effect of change in accounting principle per limited partner unit	0.08			—
Diluted net income per limited partner unit	$	0.71		$	0.43

(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 $0.04 for the three months ended 2006.

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

FINANCIAL DATA RECONCILIATIONS
(in millions, except per unit data)
	Three Months Ended March 31,
	2006			2005
Earnings before interest, taxes, depreciation and amortization (“EBITDA”)
Net income reconciliation
EBITDA	$	100.3		$	66.5
Depreciation and amortization	(21.6		)	(19.1		)
Earnings before interest and taxes (“EBIT”)	78.7			47.4
Interest expense	(15.3		)	(14.6		)
Net income	$	63.4		$	32.8
Cash flow from operating activities reconciliation
EBITDA	$	100.3		$	66.5
Interest expense	(15.3		)	(14.6		)
Net change in assets and liabilities, net of acquisitions	(555.4		)	(340.3		)
Other items to reconcile to cash flows from operating activities:
Equity (earnings) loss in PAA/Vulcan Gas Storage, LLC	0.2			—
Loss on foreign currency revaluation	0.9			0.5
SFAS 133 mark-to-market adjustment	0.7			13.4
LTIP charge	10.6			2.2
Non-cash amortization of terminated interest rate hedging instruments	0.4			0.4
Net cash used in operating activities	$	(457.6	)	$	(271.9	)

	Three Months Ended March 31,
	2006			2005
Funds flow from operations (“FFO”)
Net income	$	63.4		$	32.8
Equity (earnings) loss in PAA/Vulcan Gas Storage, LLC	0.2			—
Depreciation and amortization	21.6			19.1
Non-cash amortization of terminated interest rate hedging instruments	0.4			0.4
FFO	85.6			52.3
Maintenance capital expenditures	(4.7		)	(4.0		)
FFO after maintenance capital expenditures	$	80.9		$	48.3

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

FINANCIAL DATA RECONCILIATIONS (Continued)
(in millions, except per unit data)
	Three Months Ended March 31,
	2006			2005
Selected items impacting comparability
LTIP charge	$	(10.6	)	$	(2.2	)
Cumulative effect of change in accounting principle—LTIP	6.3			—
Loss on foreign currency revaluation	(0.9		)	(0.8		)
SFAS 133 mark-to-market adjustment	(0.7		)	(13.4		)
Pro forma additional GP distribution under EITF 03-06(1)	—			—
Selected items impacting comparability	(5.9		)	(16.4		)
GP 2% portion of selected items impacting comparability	0.1			0.3
LP 98% portion of selected items impacting comparability	$	(5.8	)	$	(16.1	)
Impact to basic net income per limited partner unit(1)	$	(0.11	)	$	(0.24	)
Impact to diluted net income per limited partner unit(1)	$	(0.11	)	$	(0.24	)

(1)The application of EITF 03-06 negatively impacted basic and diluted earnings per limited partner unit by approximately $0.04 for the three months ended 2006.

	Three Months Ended March 31,
	2006		2005
Net income and earnings per limited partner unit excluding selected items impacting comparability
Net income	$	63.4	$	32.8
Selected items impacting comparability	5.9		16.4
Adjusted net income	$	69.3	$	49.2
Net income available for limited partners under EITF 03-06	$	53.8	$	29.3
Limited partners 98% of selected items impacting comparability	5.8		16.1
Pro forma additional general partner distribution under EITF 03-06	2.9		—
Adjusted limited partners net income	$	62.5	$	45.4
Adjusted basic net income per limited partner unit	$	0.84	$	0.67
Adjusted diluted net income per limited partner unit	$	0.82	$	0.67
Basic weighted average units outstanding	74.0		67.5
Diluted weighted average units outstanding	75.7		68.2

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

FINANCIAL DATA RECONCILIATIONS (Continued)
(in millions, except per unit data)
	Three Months Ended March 31,
	2006		2005
EBITDA excluding selected items impacting comparability
EBITDA	$	100.3	$	66.5
Selected items impacting comparability	5.9		16.4
Adjusted EBITDA	$	106.2	$	82.9

	Three Months Ended March 31, 2006
	Pipeline			GMT&S
2006 Segment profit excluding selected items impacting comparability
Reported segment profit		$	38.0		$	55.9
Selected items impacting comparability of segment profit:
LTIP charge		4.9			5.7
Loss on foreign currency revaluation		—			0.9
SFAS 133 mark-to-market adjustment		—			0.7
Segment profit excluding selected items impacting comparability		$	42.9		$	63.2

	Three Months Ended March 31, 2005
	Pipeline			GMT&S
2005 Segment profit excluding selected items impacting comparability
Reported segment profit		$	50.1		$	16.3
Selected items impacting comparability of segment profit:
LTIP charge		1.3			0.9
Loss on foreign currency revaluation		—			0.8
SFAS 133 mark-to-market adjustment		—			13.4
Segment profit excluding selected items impacting comparability		$	51.4		$	31.4