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) – February 26, 2003 
 
Plains All American Pipeline, L.P. 
(Name of Registrant as specified in its charter) 
 
DELAWARE	 	0-9808	 	76-0582150	
(State or other jurisdiction	 	(Commission File Number)	 	(I.R.S. Employer	
of incorporation or organization)	 	 	 	Identification No.)	
 
333 Clay Street, Suite 1600 
Houston, Texas 77002 
(713) 646-4100 
(Address, including zip code, and telephone number, 
including area code, of Registrant’s principal executive offices) 
 
N/A 
(Former name or former address, if changed since last report.) 

 
Item 9.     Regulation FD Disclosure 

In accordance with General Instruction B.2. of Form 8-K, the information presented under this Item 9 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 First Quarter and Full Year 2003 Estimates 
 
The following table reflects the Partnership’s current estimates of certain results for the first quarter of 2003 and full year ending December 31, 2003. These estimates are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management’s assumptions and our future performance are both subject to a wide range of business risks and uncertainties, so we cannot assure you that these goals and estimates can or will be met. Please refer to the information under the caption “Forward-Looking Statements and Associated Risks” below. These risks and uncertainties could cause our actual results to differ materially from those in the following table. The estimates set forth below are given as of the date hereof, based only on information known to us as of February 25, 2003. 
 
Operating and Financial Guidance 
(in thousands except per unit data) 
 
 	  	Quarter Ended
March 31, 2003
	  	Year Ended
December 31, 2003
	
 	  	Low
	  	High
	  	Low
	  	High
	
Gross Margin:	  	 	 	  	 	 	  	 	 	  	 	 	
Pipeline	  	$	21,000	  	$	22,000	  	$	96,800	  	$	98,800	
GMT&S (1)	  	 	29,700	  	 	30,500	  	 	109,500	  	 	112,500	
 	  			  			  			  			
Total Gross Margin	  	 	50,700	  	 	52,500	  	 	206,300	  	 	211,300	
G&A / Other Expenses	  	 	12,700	  	 	12,500	  	 	48,300	  	 	47,300	
 	  			  			  			  			
EBITDA	  	$	38,000	  	$	40,000	  	$	158,000	  	$	164,000	
Depreciation & Amortization	  	 	10,900	  	 	10,800	  	 	44,750	  	 	44,500	
 	  			  			  			  			
EBIT	  	 	27,100	  	 	29,200	  	 	113,250	  	 	119,500	
Interest Expense	  	 	9,000	  	 	8,700	  	 	37,600	  	 	37,000	
 	  			  			  			  			
Adjusted Income	  	$	18,100	  	$	20,500	  	$	75,650	  	$	82,500	
Adjusted Income to Limited Partners	  	 	16,750	  	 	19,102	  	 	70,186	  	 	76,899	
Weighted Average Units Outstanding	  	 	49,578	  	 	49,578	  	 	49,578	  	 	49,578	
Adjusted Income Per Unit	  	$	0.34	  	$	0.39	  	$	1.42	  	$	1.55	
 
(1) GMT&S – Gathering, Marketing, Terminalling, & Storage 

Notes and Assumptions: 
 
1.	 	EBITDA means Earnings Before Interest, Taxes, Depreciation, and Amortization. EBIT means EBITDA less Depreciation and Amortization. Adjusted income means net income before unusual or non-recurring items and the impact of Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The forecast presented above does not include any assumptions or projections with respect to any potential gains or losses related to SFAS 133. The potential gains or losses related to SFAS 133 could materially change reported net income (related primarily to non-cash, mark-to-market gains or losses). 	
 
2.	 	Pipeline Gross Margin. Pipeline volume and tariff estimates are based on historical operating performance and our outlook for future performance. Actual results could vary materially depending on volumes that are shipped. Average pipeline volumes are estimated to be approximately 805,000 barrels per day for the first quarter of 2003, with Outer Continental Shelf (OCS) volumes estimated to make up approximately 8% of these volumes, or approximately 62,000 barrels per day. Volumes on Basin Pipeline for the first quarter are forecast at approximately 210,000 barrels per day. The volume forecast assumes that Rancho pipeline is shut down as of March 1st. Average pipeline volumes for the full year are forecast to be approximately 850,000 barrels per day including average OCS and Basin volumes of 62,000 barrels per day and 245,000 barrels per day, respectively. Revenues are forecast using these volume assumptions, current and forecast tariffs and estimates of operating expenses, each of which management believes are reasonable. A 5,000 barrel per day variance in OCS volumes would have an approximate $770,000 effect on tariff revenue for the first quarter and an approximate $3.1 million effect on an annualized basis. An average 25,000 barrel per day variance in the Basin Pipeline System, which is equivalent to an approximate 10% volume variance on that pipeline system, would have an approximate $945,000 effect on tariff revenue for the first quarter and an approximate $3.8 million effect on an annualized basis. 	
 
3.	 	Gathering, Marketing, Terminalling and Storage Gross Margin. Forecast volumes for Gathering & Marketing are approximately 440,000 barrels per day for the first quarter of 2003 and 460,000 barrels per day for the full year. This volume forecast is slightly below 2002 volumes due to projected decreases in our bulk purchase activities, which carry lower margins than our lease gathering business. Gross margin is forecast using these volume assumptions and estimates of unit margins and operating expenses, each of which management believes are reasonable. 	
 
4.	 	General and Administrative Expense. G&A expense is forecast to be between $12.5 million and $12.7 million for the first quarter of 2003, and between $47.3 million and $48.3 million for the full year. This is based on current and forecast staffing levels and includes our most recent estimate of forecast increases over 2002 related to compliance with the Sarbanes-Oxley Act and other corporate governance initiatives. 	
 
5.	 	Interest Expense. First quarter interest expense is forecast to be between $8.7 million and $9.0 million assuming an average debt balance of approximately $540 million and an average interest rate of approximately 6.5%, including our current interest rate hedges and commitment fees. Interest expense for the full year 2003 is estimated to be between $37 million and $37.6 million assuming an average debt balance of approximately $610 million and an average interest rate of 6.1%, which incorporates current 	

interest rate hedges and commitment fees. The forecast is based on estimated cash flow, current distribution rates, planned capital projects, planned sales of surplus equipment, and forecast levels of inventory and other working capital sources and uses, each of which management believes is reasonable. 
 
6.	 	Depreciation & Amortization. Depreciation and amortization is forecast based on our existing assets and forecast capital expenditures. Depreciation is computed using the straight-line method over estimated useful lives which range from 5 years for office property and equipment to 40 years for certain crude oil terminals and facilities. Crude oil pipelines are depreciated over 30 years. Effective January 1, 2003 we adopted Statement of Financial Accounting Standards (SFAS) No. 143, “Asset Retirement Obligations,” as required. Certain of our assets, primarily related to our pipeline operations segment, have obligations to perform removal and remediation activities when the asset is retired. However, the fair value of the asset retirement obligations cannot be reasonably estimated, as the settlement dates are indeterminate. Therefore, the adoption of this statement did not have an impact on the amounts included in the foregoing financial results. A cumulative adjustment related to these asset retirement obligations will be recorded in the period in which settlement dates are determined. 	
 
7.	 	Units Outstanding. Our forecast is based on the 49,577,748 units that are currently outstanding. 	
 
8.	 	Adjusted Income per Unit. Adjusted income per limited partner unit is calculated by dividing the adjusted income allocated to limited partners by the weighted average units outstanding during the period. As noted below, the adjusted income allocated to limited partners is impacted by the amount of the incentive distribution paid to the general partner. 	
 
9.	 	Potential Effect of Changes in Capital Structure. Interest expense, adjusted income and adjusted income per unit estimates are based on our capital structure as of February 25, 2003. In keeping with our established financial growth strategy of financing acquisitions using a balance of equity and debt, we anticipate that we will issue equity in order to reduce debt associated with any future acquisitions. Depending on the terms, any such equity issuance may dilute the adjusted income per unit forecasts included in the foregoing table. In addition, we intend to monitor debt capital market conditions and may in the future issue additional senior unsecured notes, which may bear interest costs greater than the amount included in the foregoing guidance. Accordingly, the foregoing financial results and per unit estimates will change, depending on the timing and the terms of any debt or equity we actually issue. Additionally, financing transactions may result in our retiring some of our outstanding debt, which could result in a charge to earnings of any unamortized debt issuance costs. We have not included any such potential charge in our forecast. 	
 
10.	 	Adjusted Income to Limited Partners. The forecast is based on our current annual distribution rate of $2.15 per unit. The amount of adjusted income allocated to our limited partnership interests is 98% of the total partnership adjusted income less the amount of the general partner’s incentive distribution. Based on a $2.15 annual distribution level and the current units outstanding, our general partner’s incentive distribution is forecast to be approximately $4.0 million annually. The amount of the incentive distribution changes based on the number of units outstanding and the level of the distribution on the units. 	

11.	 	Capital Expenditures. Expansion capital expenditures are forecast to be approximately $83 million for 2003, including approximately $8 million of capital earmarked for the East Texas to Cushing pipeline that will not actually be spent until 2004. This capital is required to bring the system up to our operating specifications. Expansion capital includes several internal expansion projects, the East Texas to Cushing pipeline acquisition that closed in January, and two relatively small acquisitions currently being negotiated and expected to close in the next 60 days. Maintenance capital expenditures are forecast to be approximately $1.7 million for the first quarter of 2003 and approximately $8.5 million for the full year. During 2003, we forecast additional pipeline linefill requirements totaling approximately $29 million. 	
 
12.	 	Non-Cash Compensation. We have not included in this table the effect of potential vesting of unit grants under our Long-Term Incentive Plan, which permits the grant of restricted units and unit options covering an aggregate of approximately 1.4 million units. Approximately 1.0 million restricted units (and no unit options) have been granted and are currently outstanding under the Plan. A restricted unit grant entitles the grantee to receive a common unit upon the vesting of the restricted unit. Subject to additional vesting requirements, restricted units may vest in the same proportion as the conversion of the partnership’s outstanding subordinated units into common units. Certain of the restricted unit grants contain additional vesting requirements tied to the partnership achieving targeted distribution thresholds, generally $2.10, $2.30 and $2.50 per unit, in equal proportions. 	
 
Under generally accepted accounting principles, we are required to recognize an expense for the vesting of the units when the financial tests for conversion of subordinated units and required distribution levels are met. The test associated with the conversion of subordinated units to common units is set forth in the partnership agreement and involves GAAP accounting concepts as well as complex and esoteric cash receipts and disbursement concepts that are indexed to the minimum quarterly distribution rate of $1.80 per limited partner unit. 
 
Because of this complexity, it is difficult to forecast when the vesting of these restricted units will occur. However, at the current distribution level of $2.15 per unit, assuming the subordination conversion test is met, the costs associated with the vesting of up to approximately 845,000 units would be incurred or accrued in the second half of 2003 or the first quarter of 2004. At a distribution level of $2.30 to $2.49, the number of units would be approximately 935,000. At a distribution level at or above $2.50, the number of units would be approximately 1,025,000. We are currently planning to issue units to satisfy the first 975,000 vested and delivered (after any units withheld for taxes), and to purchase units in the open market to satisfy any vesting obligations in excess of that amount. Issuance of units would result in a non-cash compensation expense. Purchase of units would result in a cash charge to compensation expense. In addition, the “company match” portion of payroll taxes, plus the value of any units withheld for taxes, would result in a cash charge. The amount of the charge to expense will be determined by the unit price on the date vesting occurs multiplied by the number of units. 
 
13.	 	Although acquisitions comprise a key element of our growth strategy, these results and estimates do not include any assumptions or forecasts for any acquisitions that may be made after the date hereof other than those mentioned above. 	

 
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 crude oil production located offshore California and transported on the All American Pipeline; 	
•	 	declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers; 	
•	 	the availability of adequate supplies of and demand for crude oil in the areas in which we operate; 	
•	 	the effects of competition; 	
•	 	the success of our risk management activities; 	
•	 	the impact of crude oil price fluctuations; 	
•	 	the availability (or lack thereof) of acquisition or combination opportunities; 	
•	 	successful integration and future performance of acquired assets; 	
•	 	continued creditworthiness of, and performance by, our counterparties; 	
•	 	successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil; 	
•	 	our levels of indebtedness and our ability to receive credit on satisfactory terms; 	
•	 	shortages or cost increases of power supplies, materials or labor; 	
•	 	weather interference with business operations or project construction; 	
•	 	the impact of current and future laws and governmental regulations; 	
•	 	the currency exchange rate of the Canadian dollar; 	
•	 	environmental liabilities that are not covered by an indemnity or insurance; 	
•	 	fluctuations in the debt and equity markets; 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. 

 
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.	
		
Date: February 26, 2003	 	By:      Plains AAP, L. P., its general partner	
		
 	 	By:      Plains All American GP LLC, its general partner	
		
 	 	By:      /s/ Phil Kramer
	
 	 	Name:  Phil Kramer	
 	 	Title:    Executive Vice President and Chief Financial Officer