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)—April 28, 2005
Plains All American Pipeline, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE	 	1-14569	 	76-0582150	
(State or other jurisdiction
of incorporation)	 	(Commission
File Number)	 	(IRS Employer
Identification No.)	
 
333 Clay Street, Suite 1600, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code 713-646-4100
(Former name or former address, if changed since last report.)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
o               Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o               Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o               Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o               Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 9.01.   Financial Statements and Exhibits
(c)          Exhibit 99.1—Press Release dated April 28, 2005
Item 2.02 and 7.01.   Regulation FD Disclosure; Results of Operations and Financial Condition
Plains All American Pipeline, L.P. (the “Partnership”) today issued a press release reporting its first quarter 2005 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. We are also furnishing pursuant to Item 7.01 its projections of certain operating and financial results for the second quarter of 2005 and modifying certain aspects of our previous guidance for financial performance for the full year of calendar 2005. In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities 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 2005 Estimates; Update of Full Year 2005 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 periods presented. We also 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 on EBITDA, Net Income and Net Income per limited partner unit of our long-term incentive program, potential future revaluations of foreign currency and, to the extent known, gains and losses related to SFAS 133 (primarily non-cash, mark-to-market adjustments).
The following guidance for the three months ending June 30, 2005 and the six months and twelve months ending December 31, 2005 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 and also include projections for several recent acquisitions, 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 April 27, 2005. We undertake no obligation to publicly update or revise any forward-looking statements.
2

Plains All American Pipeline, L.P.
Operating and Financial Guidance
(in millions, except per unit data)
 	 	Actual	 	Guidance(1)	 	
 	 	Three Months	 	Three Months Ended	 	Six Months Ended	 	Twelve Months Ended	 	
 	 	Ended	 	June 30, 2005	 	December 31, 2005	 	December 31, 2005	 	
 	 	March 31, 2005	 	    Low    	 	    High    	 	    Low    	 	    High    	 	    Low    	 	    High    	 	
Pipeline Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net revenues	 	 	$	95.5	 	 	 	$	91.0	 	 	 	$	93.5	 	 	 	$	189.4	 	 	 	$	190.4	 	 	 	$	375.9	 	 	 	$	379.4	 	 	
Field operating costs	 	 	(34.1	)	 	 	(35.6	)	 	 	(34.4	)	 	 	(73.1	)	 	 	(71.7	)	 	 	(142.8	)	 	 	(140.2	)	 	
General and administrative expenses	 	 	(11.3	)	 	 	(12.8	)	 	 	(12.1	)	 	 	(26.3	)	 	 	(25.3	)	 	 	(50.4	)	 	 	(48.7	)	 	
 	 	 	50.1	 	 	 	42.6	 	 	 	47.0	 	 	 	90.0	 	 	 	93.4	 	 	 	182.7	 	 	 	190.5	 	 	
Gathering, Marketing, Terminalling & Storage Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net revenues	 	 	56.8	 	 	 	74.0	 	 	 	76.5	 	 	 	126.4	 	 	 	128.7	 	 	 	257.2	 	 	 	262.0	 	 	
Field operating costs	 	 	(29.7	)	 	 	(29.0	)	 	 	(28.4	)	 	 	(60.5	)	 	 	(59.6	)	 	 	(119.2	)	 	 	(117.7	)	 	
General and administrative expenses	 	 	(10.8	)	 	 	(11.2	)	 	 	(10.7	)	 	 	(21.6	)	 	 	(21.2	)	 	 	(43.6	)	 	 	(42.7	)	 	
 	 	 	16.3	 	 	 	33.8	 	 	 	37.4	 	 	 	44.3	 	 	 	47.9	 	 	 	94.4	 	 	 	101.6	 	 	
Segment Profit	 	 	66.4	 	 	 	76.4	 	 	 	84.4	 	 	 	134.3	 	 	 	141.3	 	 	 	277.1	 	 	 	292.1	 	 	
Depreciation and amortization expense	 	 	(19.1	)	 	 	(19.1	)	 	 	(18.8	)	 	 	(39.5	)	 	 	(38.8	)	 	 	(77.7	)	 	 	(76.7	)	 	
Interest expense	 	 	(14.6	)	 	 	(14.9	)	 	 	(14.5	)	 	 	(32.8	)	 	 	(32.2	)	 	 	(62.3	)	 	 	(61.3	)	 	
Other Income (Expense)	 	 	0.1	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	0.1	 	 	 	0.1	 	 	
Net Income	 	 	$	32.8	 	 	 	$	42.4	 	 	 	$	51.1	 	 	 	$	62.0	 	 	 	$	70.3	 	 	 	$	137.2	 	 	 	$	154.2	 	 	
Net Income to Limited Partners	 	 	$	29.3	 	 	 	$	38.1	 	 	 	$	46.6	 	 	 	$	53.9	 	 	 	$	62.0	 	 	 	$	121.4	 	 	 	$	138.0	 	 	
Basic:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted Average Units Outstanding	 	 	67.5	 	 	 	67.9	 	 	 	67.9	 	 	 	67.9	 	 	 	67.9	 	 	 	67.9	 	 	 	67.9	 	 	
Net Income Per Limited Partner Unit	 	 	$	0.43	 	 	 	$	0.56	 	 	 	$	0.69	 	 	 	$	0.79	 	 	 	$	0.91	 	 	 	$	1.79	 	 	 	$	2.03	 	 	
Diluted:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted Average Units Outstanding	 	 	68.2	 	 	 	69.3	 	 	 	69.3	 	 	 	69.3	 	 	 	69.3	 	 	 	69.1	 	 	 	69.1	 	 	
Net Income Per Limited Partner Unit	 	 	$	0.43	 	 	 	$	0.55	 	 	 	$	0.67	 	 	 	$	0.78	 	 	 	$	0.90	 	 	 	$	1.76	 	 	 	$	2.00	 	 	
EBIT	 	 	$	47.4	 	 	 	$	57.3	 	 	 	$	65.6	 	 	 	$	94.8	 	 	 	$	102.5	 	 	 	$	199.5	 	 	 	$	215.5	 	 	
EBITDA	 	 	$	66.5	 	 	 	$	76.4	 	 	 	$	84.4	 	 	 	$	134.3	 	 	 	$	141.3	 	 	 	$	277.2	 	 	 	$	292.2	 	 	

Selected Items Impacting Comparability	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
LTIP charge	 	 	$	(2.2	)	 	 	$	(5.6	)	 	 	$	(5.6	)	 	 	$	(10.8	)	 	 	$	(10.8	)	 	 	$	(18.6	)	 	 	$	(18.6	)	 	
FAS 133 non-cash mark-to-market adjustment	 	 	(13.4	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(13.4	)	 	 	(13.4	)	 	
FX gain (loss)	 	 	(0.8	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(0.8	)	 	 	(0.8	)	 	
 	 	 	$	(16.5	)	 	 	$	(5.6	)	 	 	$	(5.6	)	 	 	$	(10.8	)	 	 	$	(10.8	)	 	 	$	(32.8	)	 	 	$	(32.8	)	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Excluding Selected Items Impacting Comparability	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	 	$	82.9	 	 	 	$	82.0	 	 	 	$	90.0	 	 	 	$	145.1	 	 	 	$	152.1	 	 	 	$	310.0	 	 	 	$	325.0	 	 	
Adjusted Net Income	 	 	$	49.3	 	 	 	$	48.0	 	 	 	$	56.7	 	 	 	$	72.8	 	 	 	$	81.1	 	 	 	$	170.0	 	 	 	$	187.0	 	 	
Adjusted Basic Net Income per Limited Partner Unit	 	 	$	0.67	 	 	 	$	0.64	 	 	 	$	0.77	 	 	 	$	0.95	 	 	 	$	1.07	 	 	 	$	2.26	 	 	 	$	2.51	 	 	
Adjusted Diluted Net Income per Limited Partner Unit	 	 	$	0.67	 	 	 	$	0.63	 	 	 	$	0.75	 	 	 	$	0.93	 	 	 	$	1.05	 	 	 	$	2.22	 	 	 	$	2.46	 	 	

(1)    The projected average foreign exchange rate is $1.25 CAD to $1 USD
3

Notes and Significant Assumptions:
1.                 Definitions.
EBIT	 	Earnings before interest and taxes	
EBITDA	 	Earnings before interest, taxes and depreciation and amortization expense	
Bbl/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	
 
2.                 Pipeline Operations.   Pipeline volume estimates are based on historical and anticipated future operating performance. Actual segment profit could vary materially depending on the level of volumes transported. The following table summarizes our pipeline volumes and breaks out the major systems that are significant either in total volumes transported or in contribution to total net revenue.
 	 	Calendar 2005	 	
 	 	Actual	 	Guidance	 	
 	 	Three Months	 	Three Months	 	Six Months	 	Twelve Months	 	
 	 	Ended	 	Ended	 	Ended	 	Ended	 	
 	 	March 31	 	June 30	 	December 31	 	December 31	 	
Average Daily Volumes (000’s Bbl/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
All American	 	 	54	 	 	 	54	 	 	 	54	 	 	 	54	 	 	
Basin	 	 	277	 	 	 	292	 	 	 	280	 	 	 	282	 	 	
Capline	 	 	160	 	 	 	157	 	 	 	132	 	 	 	145	 	 	
Cushing to Broome	 	 	23	 	 	 	76	 	 	 	80	 	 	 	66	 	 	
West Texas / New Mexico area systems(1)	 	 	401	 	 	 	384	 	 	 	381	 	 	 	387	 	 	
Other	 	 	546	 	 	 	561	 	 	 	555	 	 	 	551	 	 	
 	 	 	1,461	 	 	 	1,524	 	 	 	1,482	 	 	 	1,487	 	 	
Canada(2)	 	 	268	 	 	 	266	 	 	 	268	 	 	 	268	 	 	
 	 	 	1,729	 	 	 	1,790	 	 	 	1,750	 	 	 	1,755	 	 	

(1)    The aggregate of 10 systems in the West Texas / New Mexico area.
(2)    The aggregate of 7 systems.
Average volumes for the second quarter are expected to be in the range of 1,790,000 Bbl/d, compared to an average 1,729,000 Bbl/d for the three months ended March 31. The volume growth for the second quarter and the year is driven primarily by the start-up of the Cushing to Broome pipeline system late in the first quarter, which is expected to exit the year at 80,000 Bbl/d.
4

Net revenues were forecasted 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. To illustrate the impact volume changes may have on segment profit, the following table provides a volume sensitivity analysis of three systems representing approximately 30% of total pipeline net revenues.
Volume Sensitivity Analysis	 	 	
 	 	 	 	 	 	Increase /	 	
 	 	Increase /	 	% of	 	(Decrease)	 	
 	 	(Decrease)	 	System	 	in Annualized	 	
System	 	 	 	in Volume	 	Total	 	Segment Profit	 	
 	 	(Bbls/d)	 	 	 	(in millions)	 	
All American	 	 	5,000	 	 	 	9	%	 	 	$	3.2	 	 	
Basin	 	 	20,000	 	 	 	7	%	 	 	1.7	 	 	
Capline	 	 	10,000	 	 	 	6	%	 	 	1.4	 	 	

3.                 Gathering, Marketing, Terminalling and Storage Operations.   The degree of price volatility in the crude oil market influences the level of profit in the GMT&S segment. As a result of the higher volatility experienced during the first four months of 2005, segment profit in the first six months of 2005 is currently expected to be higher than the last half of 2005 based on the expectation of volatility returning to historical levels. Volumes from crude oil lease gathering are projected to average 630,000 Bbl/d in the second quarter and increase to an average of 640,000 Bbl/d for the last half of the year. LPG volumes are influenced by seasonal demands with volumes decreasing during the summer months. As such, second quarter volumes are expected to average 24,000 Bbl/d versus the annual average of 54,000 Bbl/d.
 	 	Calendar 2005	 	
 	 	Actual	 	Guidance	 	
 	 	Three Months	 	Three Months	 	Six Months	 	Twelve Months	 	
 	 	Ended	 	Ended	 	Ended	 	Ended	 	
 	 	March 31	 	June 30	 	December 31	 	December 31	 	
Average Daily Volumes (000’s Bbl/d)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Crude Oil Lease Gathering	 	 	622	 	 	 	630	 	 	 	640	 	 	 	633	 	 	
LPG	 	 	84	 	 	 	24	 	 	 	54	 	 	 	54	 	 	
 	 	 	706	 	 	 	654	 	 	 	694	 	 	 	687	 	 	
 
Segment profit is forecast using the volume assumptions stated above and estimates of unit margins, operating expenses and G&A based on current and anticipated market conditions. 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 projected segment profit per barrel for the second quarter of 2005, a 15,000 Bbl/d variance in lease gathering volumes would impact segment profit by an approximate $4.3 million on an annualized basis. A $0.01 variance in the aggregate average per-barrel margin would impact segment profit by an approximate $2.4 million on an annualized basis.
4.                 Depreciation & Amortization.   Depreciation and amortization is forecast based on our existing depreciable assets and forecast 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 50 years (for certain pipelines, crude oil terminals and facilities).
5.                 Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133).   The forecast presented above does not include assumptions or projections with respect to potential gains or losses related to SFAS 133, as there is no accurate way to forecast these potential gains or losses. The potential gains or losses related to SFAS 133 (primarily 
5

non-cash, 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 $120 million during calendar 2005, a $20 million increase over the original guidance. This increase is primarily due to additional expenditures on the Trenton system which will expand the system by 70 miles and add 18,000 barrels per day of capacity and 14,000 barrels per day of gathering volumes. Following are some of the more notable projects and estimated expenditures for 2005.
·        Trenton pipeline expansion—$34 million,
·        Capital projects associated with the Link acquisition—$18 million,
·        NW Alberta fractionator—$16 million.
·        Cushing Phase V expansion—$13 million, and
·        Shell South Louisiana Asset Acquisition—$8 million.
For the three months ended March 31, 2005, approximately $45 million of the forecasted $120 million of expansion capital was incurred in accordance with the project commitments.
Capital expenditures for maintenance projects are forecast to be approximately $19 million during 2005, of which approximately $4 million was incurred in the first quarter.
7.      Capital Structure.   The guidance is based on our capital structure as of March 31, 2005, except for the projected issuance of approximately 50,000 units to satisfy equity grants issued under the 1998 LTIP plan, and does not include any debt or equity issuances associated with acquisitions or significant capital expenditures not included in our guidance for the remainder of 2005. The crude oil market has been and is expected to continue to be volatile. In preparation for potentially higher crude oil prices and to maintain significant liquidity in such an environment, we are currently considering various transactions to increase our liquidity and financial flexibility to insure that we are well positioned to capitalize on associated opportunities in such higher priced environment. Accordingly, the foregoing financial results and per unit estimates may be impacted by future capital markets activities, depending on the timing and the terms of any debt or equity that we might issue.
8.                 Interest Expense.   Debt balances are projected based on estimated cash flows, current distribution rates, capital expenditures for maintenance and expansion projects, planned sales of surplus equipment, expected timing of collections and payments, and forecast levels of inventory and other working capital sources and uses.
Calendar 2005 interest expense is expected to be between $61.3 million and $62.3 million assuming an average long-term debt balance of approximately $990 million and an all-in average rate of approximately 6.2%. While interest on floating rate debt is based on a forward one-year LIBOR index curve of 3.5%, approximately 80% of our projected average debt balance has an average fixed interest rate of 6.0%. Included in the effective cost of debt are not only current cash payments, but also commitment fees, amortization of long-term debt discounts, and deferred amounts associated with terminated interest rate hedges. The amortization of deferred amounts associated with terminated interest rate hedges results in a non-cash component to interest expense of approximately $1.6 million per year (approximately $400,000 per quarter). Approximately 73% of these deferred amounts will be 
6

completely amortized by the fourth quarter of 2006. The remainder will be amortized over the next nine years.
Long-term debt at December 31, 2005 is projected to be approximately $1.03 billion.
9.                 Net Income per Unit.   Basic net income per limited partner unit is calculated by dividing the net income allocated to limited partners by the basic weighted average units outstanding during the period. Basic weighted average units outstanding are projected to average approximately 67.9 million units for 2005.
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. Accordingly, for each $0.05 per unit annual increase in the distribution rate up to $2.70 per unit, net income available for limited partners decreases approximately $1.0 million ($0.02 per unit) on an annualized basis. 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 $2.55 per unit, our general partner’s distribution is forecast to be approximately $17.5 million annually, of which $14.0 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.
10.          Long-term Incentive Plans.   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 generally vest on the later of 2 years, 4 years or 5 years, or achievement of annualized distribution levels of $2.60, $2.80 and $3.00 per unit, respectively, and the majority of the phantom units have a final service period vesting in 2011. Accordingly, guidance includes 1) for phantom units tied to the $2.60 performance level, an accrual over the corresponding service period, generally 2 years, as it has been deemed probable that the $2.60 performance level will be reached, and 2) for the phantom units that are not tied to the $2.60 performance threshold but have a final service period vesting in 2011, a pro rata accrual associated with a six-year service period.  For 2005, the guidance includes approximately $18.4 million of principally non-cash expense associated with these phantom units. The actual amount of LTIP expense amortization in any given year will be directly influenced by fluctuations in our unit price 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.
11.          Reconciliation of EBITDA and EBIT to Net Income.   The following table reconciles the guidance ranges for EBIT and EBITDA to net income.
 	 	Guidance	 	
 	 	Three Months Ended	 	Twelve Months Ended	 	
 	 	     June 30, 2005     	 	     December 31, 2005     	 	
 	 	     Low     	 	     High     	 	     Low     	 	     High     	 	
 	 	(in millions)	 	
Reconciliation to Net Income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
EBITDA	 	 	$	76.4	 	 	 	$	84.4	 	 	 	$	277.2	 	 	 	$	292.2	 	 	
Depreciation and amortization	 	 	19.1	 	 	 	18.8	 	 	 	77.7	 	 	 	76.7	 	 	
EBIT	 	 	57.3	 	 	 	65.6	 	 	 	199.5	 	 	 	215.5	 	 	
Interest expense	 	 	14.9	 	 	 	14.5	 	 	 	62.3	 	 	 	61.3	 	 	
Net Income	 	 	$	42.4	 	 	 	$	51.1	 	 	 	$	137.2	 	 	 	$	154.2	 	 	
 
7

Forward-Looking Statements and Associated Risks
All statements, other than statements of historical fact, included in this report 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. 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:
·       abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on our pipeline system;
·       the success of our risk management activities;
·       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;
·       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;
·       declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by third party shippers;
·       the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate;
·       successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil;
·       demand for 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 effects of competition;
·       continued creditworthiness of, and performance by, counterparties;
·       the impact of crude oil price fluctuations;
·       the impact of current and future laws, rulings and governmental regulations;
·       shortages or cost increases of power supplies, materials or labor;
·       weather interference with business operations or project construction;
·       the currency exchange rate of the Canadian dollar;
·       fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our LTIP plan; and
·       general economic, market or business conditions.
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.
8

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: April 28, 2005	By:	 /s/ PHIL KRAMER	
 	 	 Name:	Phil Kramer	
 	 	 Title:	Executive Vice President and Chief Financial Officer	
 
9

Exhibit 99.1
Contacts:	 	Phillip D. Kramer	 	A. Patrick Diamond	 	
 	 	Executive VP and CFO	 	Manager, Special Projects	 	
 	 	713/646-4560 – 800/564-3036	 	713/646-4487 – 800/564-3036	 	
 
FOR IMMEDIATE RELEASE
Plains All American Pipeline, L.P. Reports
Record Financial Results for First Quarter 2005—
Net Income Up 18%; EBITDA Up 32%
(Houston—April 28, 2005) Plains All American Pipeline, L.P. (NYSE: PAA) today reported net income of $32.8 million, or $0.43 per basic and diluted limited partner unit, for the first quarter of 2005, as compared to net income of $27.9 million, or $0.44 per basic and diluted limited partner unit, for the first quarter of 2004. As reported, earnings before interest, taxes, depreciation and amortization (“EBITDA”) for the first quarter of 2005 were $66.5 million, an increase of 32% as compared with EBITDA of $50.5 million for the first quarter of 2004. (See the section of this release entitled “Non-GAAP Financial Measures” and the attached tables for discussion of EBITDA and other non-GAAP financial measures, and reconciliations of such measures to the comparable GAAP measures.)
Adjusting for selected items impacting comparability, the Partnership’s first quarter 2005 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $49.3 million, $0.67 per basic and diluted unit, and $82.9 million, respectively. Similarly, the Partnership’s first quarter 2004 adjusted net income, adjusted net income per limited partner unit and adjusted EBITDA were $28.1 million, $0.44 per basic and diluted unit, and $50.8 million, respectively. On a comparable basis, first quarter 2005 adjusted net income, adjusted net income per diluted limited partner unit and adjusted EBITDA increased 75%, 51% and 63%, respectively, over first quarter 2004.
“Plains All American delivered record financial and operating performance for the first quarter as both of our business segments experienced solid baseline growth,” said Greg L. Armstrong, Chairman and CEO of the Partnership. “These strong results were driven by a combination of factors, including the contribution of acquisitions completed since March 1, 2004, increased transportation volumes in our pipeline segment and increased receipts of foreign crude oil at our Gulf Coast facilities. In addition, as a result of our extensive asset base and business model, we were able to capture increased margins and incremental profit opportunities in our gathering, marketing, terminalling and storage segment from contango market opportunities and continued crude oil market volatility. Given our strong first quarter results and our outlook for the second quarter that we furnished this morning via Form 8-K, the Partnership is well on its way to achieving the goals that we have set for 2005.”
Armstrong noted that the results exceeded both the Partnership’s original and upwardly revised quarterly guidance ranges for EBITDA that had been previously provided to the investment community.
—MORE—
1

The following table summarizes selected items that the Partnership believes impact the comparability of financial results between reporting periods:
 	 	For the Three
Months Ended
March 31,	 	
 	 	2005	 	2004	 	
 	 	(Dollars in millions,
except per unit data)	 	
Long-Term Incentive Plan (“LTIP”) charge	 	$ (2.2	)	$ (4.2	)	
Cumulative effect of change in accounting principle	 	—	 	(3.1	)	
Loss on foreign currency revaluation	 	(0.8	)	(0.4	)	
SFAS 133 noncash mark-to-market adjustment	 	(13.4	)	7.5	 	
Total	 	$ (16.5	)	$ (0.3	)	
Per Basic Limited Partner Unit	 	$ (0.24	)	$ (0.00	)	
Per Diluted Limited Partner Unit	 	$ (0.24	)	$ (0.00	)	
 
The following table presents certain selected financial information by segment for the first quarter reporting periods:
 	 	Pipeline
Operations 	 	Gathering,
Marketing,
Terminalling &
Storage
Operations (4)	 	
 	 	(Dollars in millions)	 	
Three Months Ended March 31, 2005	 	 	 	 	 	 	 	 	 	
Revenues(1)	 	 	$ 247.2	 	 	 	$ 6,426.2	 	 	
Purchases(1)	 	 	(151.7	)	 	 	(6,369.4	)	 	
Field operating costs (excluding LTIP charge)	 	 	(34.0	)	 	 	(29.5	)	 	
LTIP charge—operations	 	 	(0.1	)	 	 	(0.2	)	 	
Segment G&A expenses (excluding LTIP charge)(2)	 	 	(10.1	)	 	 	(10.1	)	 	
LTIP charge—general and administrative	 	 	(1.2	)	 	 	(0.7	)	 	
Segment profit	 	 	$   50.1	 	 	 	$      16.3	 	 	
Noncash SFAS 133 impact(3)	 	 	$      —	 	 	 	$    (13.4	)	 	
Maintenance capital	 	 	$     2.8	 	 	 	$        1.2	 	 	
Three Months Ended March 31, 2004	 	 	 	 	 	 	 	 	 	
Revenues(1)	 	 	$ 189.3	 	 	 	$ 3,631.3	 	 	
Purchases(1)	 	 	(136.7	)	 	 	(3,572.9	)	 	
Field operating costs (excluding LTIP charge)	 	 	(19.3	)	 	 	(18.5	)	 	
LTIP charge—operations	 	 	(0.1	)	 	 	(0.4	)	 	
Segment G&A expenses (excluding LTIP charge)(2)	 	 	(6.0	)	 	 	(9.4	)	 	
LTIP charge—general and administrative	 	 	(1.7	)	 	 	(2.0	)	 	
Segment profit	 	 	$   25.5	 	 	 	$      28.1	 	 	
Noncash SFAS 133 impact(3)	 	 	$      —	 	 	 	$        7.5	 	 	
Maintenance capital	 	 	$     1.4	 	 	 	$        0.3	 	 	

(1)                 Include intersegment amounts.
(2)                 Segment general and administrative (G&A) expenses 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 
2

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.
Segment profit from pipeline operations was up approximately 96% (88% excluding selected items impacting comparability in both periods) in the first quarter of 2005 when compared to the first quarter of 2004. Also excluding selected items impacting comparability in both periods, segment profit from gathering, marketing, terminalling and storage operations was up approximately 34%.
The Partnership’s basic weighted average units outstanding for the first quarter of 2005 totaled 67.5 million (68.2 million diluted) as compared to 58.4 million (59.0 million diluted) in last year’s first quarter. At March 31, 2005, the Partnership had approximately 67.9 million units outstanding, long-term debt of $930.2 million and a long-term debt-to-total capitalization ratio of approximately 48%.
On April 22, 2005, the Partnership declared a cash distribution of $0.6375 per unit ($2.55 per unit on an annualized basis) on its outstanding limited partner units. The distribution will be paid on May 13, 2005, to holders of record of such units at the close of business on May 3, 2005. The distribution represents an increase of approximately 13.3% over the May 2004 distribution and approximately 4.1% over the February 2005 distribution. This represents the 11th distribution increase for the Partnership in the last 18 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 2005. 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 PAA management believes 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. Management also believes 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. Management considers an understanding of these selected items impacting comparability to be material to its evaluation of our operating results and prospects. Although we present selected items that management considers 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 
3

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 Reconciliations” 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, April 28, 2005. 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 expansion and organic growth 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 of 2005; 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 call 800-473-6123, or, for international callers, 973-582-2706 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:
Call 877-519-4471 or international call 973-341-3080 and enter PIN # 5963485
The replay will be available beginning Thursday, April 28, 2005, at approximately 1:00 PM (Central) and continue until 11:59pm (Central) Monday, May 2, 2005.
Except for the historical information contained herein, the matters discussed in this news release are forward-looking statements that involve certain risks and uncertainties. These risks and uncertainties include, among other things: abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on our pipeline systems; the success of our risk management activities; the availability of, and 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; 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; declines in volumes shipped on the Basin Pipeline, Capline Pipeline and our other pipelines by the Partnership or third party shippers; the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate; successful third party drilling efforts in areas in which we operate pipelines or gather crude oil; demand for 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 effects of competition; continued credit worthiness of, and performance by, our counterparties; the impact of crude oil price fluctuations; the impact of current and future laws, rulings and government regulations; shortages or cost increases in power supplies, materials and labor; weather interference with business operations or project construction; the currency exchange rate of the Canadian dollar; fluctuation in the debt and equity capital markets (including the 
4

price of our units at the time of vesting under our LTIP); and other factors and uncertainties inherent in the marketing, transportation, terminalling, gathering and storage of crude oil and liquefied petroleum gas (“LPG”) 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. The Partnership’s common units are traded on the New York Stock Exchange under the symbol “PAA.” The Partnership is headquartered in Houston, Texas.
# # #
5

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
 	 	Three Months Ended
March 31,	 	
 	 	2005	 	2004	 	
REVENUES	 	$	6,638,496	 	$	3,804,644	 	
COSTS AND EXPENSES	 	 	 	 	 	
Purchases and related costs	 	6,486,160	 	3,693,505	 	
Field operating costs (excluding LTIP charge)	 	63,476	 	37,816	 	
LTIP charge—operations	 	344	 	567	 	
General and administrative (excluding LTIP charge)	 	20,216	 	15,478	 	
LTIP charge—general & administrative	 	1,895	 	3,661	 	
Depreciation and amortization	 	19,118	 	13,120	 	
Total costs and expenses	 	6,591,209	 	3,764,147	 	
OPERATING INCOME	 	47,287	 	40,497	 	
OTHER INCOME/(EXPENSE)	 	 	 	 	 	
Interest expense	 	(14,558	)	(9,532	)	
Interest and other income (expense), net	 	79	 	41	 	
Income before cumulative effect of change in accounting principle	 	32,808	 	31,006	 	
Cumulative effect of change in accounting principle	 	—	 	(3,130	)	
NET INCOME	 	$	32,808	 	$	27,876	 	
NET INCOME—LIMITED PARTNER	 	$	29,265	 	$	25,707	 	
NET INCOME—GENERAL PARTNER	 	$	3,543	 	$	2,169	 	
BASIC NET INCOME PER LIMITED PARTNER UNIT	 	 	 	 	 	
Income before cumulative effect of change in accounting principle	 	$	0.43	 	$	0.49	 	
Cumulative effect of change in accounting principle	 	—	 	(0.05	)	
Basic net income per limited partner unit	 	$	0.43	 	$	0.44	 	
DILUTED NET INCOME PER LIMITED PARTNER UNIT	 	 	 	 	 	
Income before cumulative effect of change in accounting principle	 	$	0.43	 	$	0.49	 	
Cumulative effect of change in accounting principle	 	—	 	(0.05	)	
Diluted net income per limited partner unit	 	$	0.43	 	$	0.44	 	
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING	 	67,517	 	58,414	 	
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING	 	68,156	 	59,017	 	
OPERATING DATA (in thousands)(1)	 	 	 	 	 	
Average Daily Volumes (barrels)	 	 	 	 	 	
Pipeline activities:	 	 	 	 	 	
Tariff activities	 	 	 	 	 	
All American	 	54	 	55	 	
Basin	 	277	 	275	 	
Capline(2)	 	160	 	54	 	
West Texas/New Mexico Area Systems(3)	 	401	 	209	 	
Canada	 	268	 	240	 	
Other	 	494	 	143	 	
Pipeline margin activities	 	75	 	72	 	
Total	 	1,729	 	1,048	 	
Crude oil lease gathering	 	622	 	460	 	
Crude oil bulk purchases	 	157	 	122	 	
Total crude oil	 	779	 	582	 	
LPG sales	 	84	 	59	 	

(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)          Capline volumes averaged approximately 160,000 barrels per day for March 2004, which is the period we owned the system. This calculates to approximately 54,000 barrels per day over the first quarter of 2004.
(3)          The aggregate of ten systems in the West Texas / New Mexico area.
6

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (Continued)
FINANCIAL DATA RECONCILIATIONS
(in thousands)
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2005	 	2004	 	
Earnings before interest, taxes, depreciation and amortization (“EBITDA”)	 	 	 	 	 	
Net income reconciliation	 	 	 	 	 	
EBITDA	 	$	66,484	 	$	50,528	 	
Depreciation and amortization	 	(19,118	)	(13,120	)	
Earnings before interest and taxes (“EBIT”)	 	47,366	 	37,408	 	
Interest expense	 	(14,558	)	(9,532	)	
Net Income	 	$	32,808	 	$	27,876	 	
Cash flow from operating activities reconciliation	 	 	 	 	 	
EBITDA	 	$	66,484	 	$	50,528	 	
Interest expense	 	(14,558	)	(9,532	)	
Net change in assets and liabilities, net of acquisitions	 	(340,351	)	91,358	 	
Other items to reconcile to cash flows from operating activities:	 	 	 	 	 	
Cumulative effect of change in accounting principle	 	—	 	3,130	 	
Non-cash loss on foreign currency revaluation	 	544	 	410	 	
SFAS 133 noncash mark-to-market adjustment	 	13,406	 	(7,498	)	
LTIP charge	 	2,239	 	4,228	 	
Non-cash amortization of terminated interest rate hedging instruments	 	387	 	357	 	
Net cash provided by (used in) operating activities	 	$	(271,849	)	$	132,981	 	
Funds flow from operations (FFO)	 	 	 	 	 	
Net Income	 	$	32,808	 	$	27,876	 	
Depreciation and amortization	 	19,118	 	13,120	 	
Non-cash amortization of terminated interest rate hedging instruments	 	387	 	357	 	
FFO	 	52,313	 	41,353	 	
Maintenance capital expenditures	 	(3,972	)	(1,748	)	
FFO after maintenance capital expenditures	 	$	48,341	 	$	39,605	 	
Selected items impacting comparability	 	 	 	 	 	
LTIP charge	 	$	(2,239	)	$	(4,228	)	
Cumulative effect of change in accounting principle	 	—	 	(3,130	)	
Loss on foreign currency revaluation	 	(820	)	(410	)	
SFAS 133 noncash mark-to-market adjustment	 	(13,406	)	7,498	 	
Selected items impacting comparability	 	(16,465	)	(270	)	
GP 2% portion of selected items impacting comparability	 	329	 	5	 	
LP 98% portion of selected items impacting comparability	 	$	(16,136	)	$	(265	)	
Impact to basic net income per limited partner unit	 	$	(0.24	)	$	(0.00	)	
Impact to diluted net income per limited partner unit	 	$	(0.24	)	$	(0.00	)	
 
7

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (Continued)
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2005	 	2004	 	
Financial measures excluding selected items impacting comparability	 	 	 	 	 	
EBITDA	 	$	66,484	 	$	50,528	 	
Selected items impacting comparability	 	16,465	 	270	 	
Adjusted EBITDA	 	$	82,949	 	$	50,798	 	
Net Income	 	$	32,808	 	$	27,876	 	
Selected items impacting comparability	 	16,465	 	270	 	
Adjusted Net Income	 	$	49,273	 	$	28,146	 	
Adjusted Net Income	 	$	49,273	 	$	28,146	 	
GP Incentive	 	(2,946	)	(1,644	)	
Subtotal	 	46,327	 	26,502	 	
GP 2%	 	(927	)	(530	)	
Adjusted LP Net Income	 	$	45,400	 	$	25,972	 	
Adjusted Basic Net Income per limited partner unit	 	$	0.67	 	$	0.44	 	
Adjusted Diluted Net Income per limited partner unit	 	$	0.67	 	$	0.44	 	
Basic weighted average units outstanding	 	67,517	 	58,414	 	
Diluted weighted average units outstanding	 	68,156	 	59,017	 	
 
 	 	Three Months Ended	 	
 	 	March 31, 2005	 	
 	 	Pipeline	 	GMT&S	 	
Segment profit excluding selected items impacting comparability	 	 	 	 	 	
Reported segment profit	 	$	50,087	 	$	16,316	 	
Selected items impacting comparability of segment profit:	 	 	 	 	 	
LTIP charge	 	1,299	 	940	 	
Loss on foreign currency revaluation	 	—	 	820	 	
SFAS 133 noncash mark-to-market adjustment	 	—	 	13,406	 	
Segment profit excluding selected items impacting comparability	 	$	51,386	 	$	31,482	 	
 
 	 	Three Months Ended	 	
 	 	March 31, 2004	 	
 	 	Pipeline	 	GMT&S	 	
Segment profit excluding selected items impacting comparability	 	 	 	 	 	
Reported segment profit	 	$	25,501	 	$	28,116	 	
Selected items impacting comparability of segment profit:	 	 	 	 	 	
LTIP charge	 	1,800	 	2,428	 	
Loss on foreign currency revaluation	 	—	 	410	 	
SFAS 133 noncash mark-to-market adjustment	 	—	 	(7,498	)	
Segment profit excluding selected items impacting comparability	 	$	27,301	 	$	23,456	 	
 
8

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FINANCIAL SUMMARY (unaudited) (Continued)
CONDENSED CONSOLIDATED BALANCE SHEET DATA
(in thousands) 
 	 	March 31,	 	 December 31, 	 	
 	 	2005	 	2004	 	
ASSETS	 	 	 	 	 	 	 	
Current assets	 	$	1,845,768	 	 	$	1,101,202	 	 	
Property and equipment, net	 	1,775,949	 	 	1,727,622	 	 	
Pipeline linefill in owned assets	 	166,147	 	 	168,352	 	 	
Inventory in third party assets	 	55,271	 	 	59,279	 	 	
Other long-term assets, net	 	91,067	 	 	103,956	 	 	
Total Assets	 	$	3,934,202	 	 	$	3,160,411	 	 	
LIABILITIES AND PARTNERS’ CAPITAL	 	 	 	 	 	 	 	
Current liabilities	 	$	1,961,316	 	 	$	1,113,717	 	 	
Long-term debt under credit facilities and other	 	132,880	 	 	151,753	 	 	
Senior notes, net of unamortized discount	 	797,360	 	 	797,271	 	 	
Other long-term liabilities and deferred credits	 	32,089	 	 	27,466	 	 	
Total Liabilities	 	2,923,645	 	 	2,090,207	 	 	
Partners’ capital	 	1,010,557	 	 	1,070,204	 	 	
Total Liabilities and Partners’ Capital	 	$	3,934,202	 	 	$	3,160,411	 	 	
 
9