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UNITED STATES 
SECURITIES AND EXCHANGE COMMISSION 
Washington, D. C. 20549 

 
FORM 10-Q 
 
☑	 	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 	
 
For the quarterly period ended March 31, 2003 
 
OR 
 
☐	 	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 	
 
Commission file number: 1-14569 

 
PLAINS ALL AMERICAN PIPELINE, L.P. 
(Exact name of registrant as specified in its charter) 
 
Delaware	    	76-0582150	
(State or other jurisdiction of
incorporation or organization)	    	(I.R.S. Employer
Identification No.)	
 
333 Clay Street, Suite 1600 
Houston, Texas 77002 
(Address of principal executive offices) 
(Zip Code) 
 
(713) 646-4100 
(Registrant’s telephone number, including area code) 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes ☑ No ☐ 
 
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).    Yes ☑ No ☐ 
 
At April 30, 2003, there were outstanding 40,885,939 Common Units, 1,307,190 Class B Common Units and 10,029,619 Subordinated Units. 

Table of Contents
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
TABLE OF CONTENTS 
 
 	  	Page
	
PART I. FINANCIAL INFORMATION	  	 	
		
Item 1.    CONSOLIDATED FINANCIAL STATEMENTS:	  	 	
Consolidated Balance Sheets:	  	 	
March 31, 2003, and December 31, 2002	  	3	
Consolidated Statements of Operations:	  	 	
For the three months ended March 31, 2003 and 2002	  	4	
Consolidated Statements of Cash Flows:	  	 	
For the three months ended March 31, 2003 and 2002	  	5	
Consolidated Statement of Partners’ Capital:	  	 	
For the three months ended March 31, 2003	  	6	
Consolidated Statements of Comprehensive Income:	  	 	
For the three months ended March 31, 2003 and 2002	  	7	
Consolidated Statement of Changes in Accumulated Other Comprehensive Income:	  	 	
For the three months ended March 31, 2003	  	7	
Notes to the Consolidated Financial Statements	  	8	
		
Item 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	  	17	
		
Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS	  	29	
		
Item 4.    CONTROLS AND PROCEDURES	  	29	
		
PART II. OTHER INFORMATION	  	 	
		
Item 1.    Legal Proceedings	  	30	
		
Item 2.    Changes in Securities and Use of Proceeds	  	30	
		
Item 3.    Defaults Upon Senior Securities	  	30	
		
Item 4.    Submission of Matters to a Vote of Security Holders 	  	30	
		
Item 5.    Other Information	  	30	
		
Item 6.    Exhibits and Reports on Form 8-K	  	31	
		
Signatures 	  	32	
		
Certification of Principal Executive Officer	  	33	
		
Certification of Principal Financial Officer	  	34	

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PART I. FINANCIAL INFORMATION 
 
Item 1.    CONSOLIDATED FINANCIAL STATEMENTS 
 
PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
CONSOLIDATED BALANCE SHEETS 
 
(in thousands, except unit data) 
 
 	  	March 31, 2003
	 	  	December 31, 2002
	 	
 	  	(unaudited)	 	  	 	 	
ASSETS	  	 	 	 	  	 	 	 	
		
CURRENT ASSETS	  	 	 	 	  	 	 	 	
Cash and cash equivalents	  	$	5,277	 	  	$	3,501	 	
Accounts receivable, net	  	 	507,184	 	  	 	499,909	 	
Inventory	  	 	43,134	 	  	 	81,849	 	
Other current assets	  	 	27,519	 	  	 	17,676	 	
 	  				  				
Total current assets	  	 	583,114	 	  	 	602,935	 	
 	  				  				
PROPERTY AND EQUIPMENT	  	 	1,101,512	 	  	 	1,030,303	 	
Accumulated depreciation	  	 	(88,478	)	  	 	(77,550	)	
 	  				  				
 	  	 	1,013,034	 	  	 	952,753	 	
 	  				  				
OTHER ASSETS	  	 	 	 	  	 	 	 	
Pipeline linefill	  	 	77,316	 	  	 	62,558	 	
Other, net	  	 	43,071	 	  	 	48,329	 	
 	  				  				
Total assets	  	$	1,716,535	 	  	$	1,666,575	 	

LIABILITIES AND PARTNERS’ CAPITAL	  	 	 	 	  	 	 	 	
		
CURRENT LIABILITIES	  	 	 	 	  	 	 	 	
Accounts payable	  	$	510,879	 	  	$	488,922	 	
Due to related parties	  	 	27,579	 	  	 	23,301	 	
Short-term debt	  	 	19,622	 	  	 	99,249	 	
Other current liabilities	  	 	29,612	 	  	 	25,777	 	
 	  				  				
Total current liabilities	  	 	587,692	 	  	 	637,249	 	
		
LONG-TERM LIABILITIES	  	 	 	 	  	 	 	 	
Long-term debt under credit facilities	  	 	323,531	 	  	 	310,126	 	
Senior notes, net of unamortized discount of $380 and $390, respectively	  	 	199,620	 	  	 	199,610	 	
Other long-term liabilities and deferred credits	  	 	14,112	 	  	 	7,980	 	
 	  				  				
Total liabilities	  	 	1,124,955	 	  	 	1,154,965	 	
 	  				  				
COMMITMENTS AND CONTINGENCIES (NOTE 6)	  	 	 	 	  	 	 	 	
		
PARTNERS’ CAPITAL	  	 	 	 	  	 	 	 	
Common unitholders (40,885,939 and 38,240,939 units outstanding at March 31, 2003, and December 31, 2002, respectively)	  	 	598,642	 	  	 	524,428	 	
Class B common unitholder (1,307,190 units outstanding at each date )	  	 	18,841	 	  	 	18,463	 	
Subordinated unitholders (10,029,619 units outstanding at each date)	  	 	(44,210	)	  	 	(47,103	)	
General partner	  	 	18,307	 	  	 	15,822	 	
 	  				  				
Total partners’ capital	  	 	591,580	 	  	 	511,610	 	
 	  				  				
 	  	$	1,716,535	 	  	$	1,666,575	 	

The accompanying notes are an integral part of these consolidated financial statements. 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
CONSOLIDATED STATEMENTS OF OPERATIONS 
 
(in thousands, except per unit data) 
 
 	  	Three Months Ended
March 31,
	 	
 	  	2003
	 	  	2002
	 	
 	  	(unaudited)	 	
REVENUES	  	$	3,281,908	 	  	$	1,545,323	 	
COST OF SALES AND OPERATIONS (excluding depreciation)	  	 	3,224,356	 	  	 	1,506,935	 	
 	  				  				
Gross margin (excluding depreciation)	  	 	57,552	 	  	 	38,388	 	
 	  				  				
EXPENSES	  	 	 	 	  	 	 	 	
General and administrative	  	 	13,072	 	  	 	10,758	 	
Depreciation-operations	  	 	9,328	 	  	 	5,908	 	
Depreciation and amortization-general and administrative	  	 	1,543	 	  	 	1,059	 	
 	  				  				
Total expenses	  	 	23,943	 	  	 	17,725	 	
 	  				  				
OPERATING INCOME	  	 	33,609	 	  	 	20,663	 	
		
OTHER INCOME/(EXPENSE)	  	 	 	 	  	 	 	 	
Interest expense (net of $52 and $102 capitalized, respectively)	  	 	(9,154	)	  	 	(6,453	)	
Interest and other income (expense), net	  	 	(104	)	  	 	71	 	
 	  				  				
NET INCOME	  	$	24,351	 	  	$	14,281	 	
 	  				  				
NET INCOME—LIMITED PARTNERS	  	$	22,876	 	  	$	13,454	 	
 	  				  				
NET INCOME—GENERAL PARTNER	  	$	1,475	 	  	$	827	 	
 	  				  				
BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT	  	$	0.46	 	  	$	0.31	 	
 	  				  				
WEIGHTED AVERAGE UNITS OUTSTANDING	  	 	50,166	 	  	 	43,253	 	

 
 
The accompanying notes are an integral part of these consolidated financial statements. 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
CONSOLIDATED STATEMENTS OF CASH FLOWS 
 
(in thousands) 
 
 	  	Three Months Ended
March 31,
	 	
 	  	2003
	 	  	2002
	 	
 	  	(unaudited)	 	
CASH FLOWS FROM OPERATING ACTIVITIES	  	 	 	 	  	 	 	 	
Net income	  	$	24,351	 	  	$	14,281	 	
Items not affecting cash flows from operating activities:	  	 	 	 	  	 	 	 	
Depreciation and amortization	  	 	10,871	 	  	 	6,967	 	
Change in derivative fair value	  	 	(930	)	  	 	2,855	 	
Changes in assets and liabilities, net of acquisitions:	  	 	 	 	  	 	 	 	
Accounts receivable and other	  	 	9,539	 	  	 	(121,581	)	
Inventory	  	 	40,114	 	  	 	37,412	 	
Pipeline linefill	  	 	(13,712	)	  	 	—  	 	
Accounts payable and other current liabilities	  	 	16,882	 	  	 	63,219	 	
Due to related parties	  	 	4,278	 	  	 	5,987	 	
 	  				  				
Net cash provided by operating activities	  	 	91,393	 	  	 	9,140	 	
 	  				  				
CASH FLOWS FROM INVESTING ACTIVITIES	  	 	 	 	  	 	 	 	
Cash paid in connection with acquisitions (Note 2)	  	 	(44,373	)	  	 	(13,160	)	
Additions to property and equipment	  	 	(15,077	)	  	 	(11,398	)	
Other investing activities	  	 	543	 	  	 	26	 	
 	  				  				
Net cash used in investing activities	  	 	(58,907	)	  	 	(24,532	)	
 	  				  				
CASH FLOWS FROM FINANCING ACTIVITIES	  	 	 	 	  	 	 	 	
Net borrowings on long-term revolving credit facility	  	 	18,788	 	  	 	39,342	 	
Net repayments on short-term letter of credit and hedged inventory facility	  	 	(85,326	)	  	 	(528	)	
Cash paid in connection with financing arrangements	  	 	(54	)	  	 	(544	)	
Net proceeds from the issuance of common units (Note 4)	  	 	63,895	 	  	 	—	 	
Distributions paid to unitholders and general partner	  	 	(28,199	)	  	 	(23,160	)	
 	  				  				
Net cash (used in) provided by financing activities	  	 	(30,896	)	  	 	15,110	 	

Effect of translation adjustment on cash	  	 	186	 	  	 	72	 	

Net increase (decrease) in cash and cash equivalents	  	 	1,776	 	  	 	(210	)	
Cash and cash equivalents, beginning of period	  	 	3,501	 	  	 	3,511	 	
 	  				  				
Cash and cash equivalents, end of period	  	$	5,277	 	  	$	3,301	 	

Cash paid for interest, net of amounts capitalized	  	$	5,846	 	  	$	4,725	 	

 
 
The accompanying notes are an integral part of these consolidated financial statements. 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL 
 
(in thousands) 
 
 	 	Common Unitholders
	 	 	Class B
Common Unitholder
	 	 	Subordinated Unitholders
	 	 	General
Partner
Amount
	 	 	Total Partners’
Capital
Amount
	 	
 	 	Units
	 	Amounts
	 	 	Units
	 	Amounts
	 	 	Units
	 	Amounts
	 	 			 			
 	 	(unaudited)	 	
Balance at December 31, 2002	 	38,241	 	$	524,428	 	 	1,307	 	$	18,463	 	 	10,030	 	$	(47,103	)	 	$	15,822	 	 	$	511,610	 	
Issuance of common units	 	2,645	 	 	62,556	 	 	—  	 	 	—  	 	 	—  	 	 	—  	 	 	 	1,339	 	 	 	63,895	 	
Distributions	 	—  	 	 	(20,554	)	 	—  	 	 	(703	)	 	—  	 	 	(5,391	)	 	 	(1,551	)	 	 	(28,199	)	
Other comprehensive income	 	—  	 	 	14,489	 	 	—  	 	 	486	 	 	—  	 	 	3,726	 	 	 	1,222	 	 	 	19,923	 	
Net income	 	—  	 	 	17,723	 	 	—  	 	 	595	 	 	—  	 	 	4,558	 	 	 	1,475	 	 	 	24,351	 	
 	 		 				 		 				 		 				 				 				
Balance at March 31, 2003	 	40,886	 	$	598,642	 	 	1,307	 	$	18,841	 	 	10,030	 	$	(44,210	)	 	$	18,307	 	 	$	591,580	 	

 

 
 
The accompanying notes are an integral part of these consolidated financial statements. 

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND 
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME 
 
(in thousands) 
 
Statements of Comprehensive Income 
 
 	  	Three Months Ended
March 31,
	 	
 	  	2003
	  	2002
	 	
 	  	(unaudited)	 	
Net income	  	$	24,351	  	$	14,281	 	
Other comprehensive income	  	 	19,923	  	 	(2,951	)	
 	  			  				
Total comprehensive income	  	$	44,274	  	$	11,330	 	

Statement of Changes in Accumulated Other Comprehensive Income 
 
 	  	Net
Deferred
Gain (Loss) on
Derivative
Instruments
	 	  	Currency
Translation
Adjustments
	 	  	Total
	 	
 	  	(unaudited)	 	
Balance at December 31, 2002	  	$	(8,207	)	  	$	(6,219	)	  	$	(14,426	)	
Current year activity	  	 	 	 	  	 	 	 	  	 	 	 	
Reclassification adjustments for settled contracts	  	 	(126	)	  	 	—  	 	  	 	(126	)	
Changes in fair value of outstanding hedge positions	  	 	4,473	 	  	 	—  	 	  	 	4,473	 	
Currency translation adjustment	  	 	—  	 	  	 	15,576	 	  	 	15,576	 	
 	  				  				  				
Total current year activity	  	 	4,347	 	  	 	15,576	 	  	 	19,923	 	
 	  				  				  				
Balance at March 31, 2003	  	$	(3,860	)	  	$	9,357	 	  	$	5,497	 	

 

The accompanying notes are an integral part of these consolidated financial statements. 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
 
(unaudited) 
 
Note 1—Organization and Accounting Policies 
 
Plains All American Pipeline, L.P., is a publicly traded Delaware limited partnership (the “Partnership”) formed in 1998 and engaged in interstate and intrastate marketing, transportation and terminalling of crude oil and liquified petroleum gas (“LPG”). Our operations are conducted directly and indirectly through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana and the Canadian provinces of Alberta and Saskatchewan. 
 
The accompanying financial statements and related notes present (i) our consolidated financial position as of March 31, 2003, and December 31, 2002, (ii) the results of our consolidated operations for the three months ended March 31, 2003 and 2002, (iii) consolidated cash flows for the three months ended March 31, 2003 and 2002, (iv) consolidated changes in partners’ capital for the three months ended March 31, 2003, (v) total consolidated comprehensive income for the three months ended March 31, 2003 and 2002, and (vi) changes in consolidated accumulated other comprehensive income for the three months ended March 31, 2003. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior period amounts to conform to current period presentation. The results of operations for the three months ended March 31, 2003 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2002 Annual Report on Form 10-K. 
 
Note 2—Acquisitions and Dispositions 
 
Red River Pipeline System 
 
In February 2003, we completed the acquisition of a 347-mile crude oil pipeline from BP Pipelines (North America) Inc. for approximately $19.3 million, including transaction costs. The system originates at Sabine in East Texas and terminates near Cushing, Oklahoma. The system also includes approximately 695,000 barrels of crude oil storage capacity. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since February 1, 2003. The entire purchase price was allocated to property and equipment. This pipeline complements our existing assets in East Texas and, upon completion of a planned interconnect, will provide another direct mainline connection to our Cushing Terminal. This acquisition did not have a material effect on either our financial position, results of operations or cash flows. 
 
Iatan Gathering System 
 
In March 2003, we completed the acquisition of a West Texas crude oil gathering system from Navajo Refining Company, L.P. for approximately $24.3 million, including transaction costs. The assets are located in the Permian Basin in West Texas and consist of approximately 315 miles of active crude oil gathering lines. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2003. The entire purchase price was allocated to property and equipment. This acquisition did not have a material effect on either our financial position, results of operations or cash flows. 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 
 
(unaudited) 

Shutdown of Rancho Pipeline System 
 
The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, terminated in March 2003. Upon termination, the agreement requires the owners to take the pipeline system, in which we own an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not accept nominations for movements after February 28, 2003. The shutdown of the Rancho Pipeline System was contemplated by us at the time we made our acquisition proposal. The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. The ultimate use of the Rancho pipeline is still being evaluated by the owners, however any value realized is expected to be minimal and relatively close to the purchase price allocated to this asset. In conjunction with the Shell acquisition in 2002 the shutdown of the Rancho pipeline was accounted for under purchase accounting in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 141 “Business Combinations.” 
 
Note 3 – Industry Credit Markets and Accounts Receivable 
 
Throughout the latter part of 2001 and all of 2002, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and extreme financial distress at several large, diversified energy companies, the energy industry has been especially impacted by these developments. Accordingly, we are exposed to an increased level of direct and indirect counterparty credit and performance risk. 
 
Our accounts receivable are primarily from purchasers and shippers of crude oil. The majority of our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. We make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided in the form of standby letters of credit. 
 
Accounts receivable included in the consolidated balance sheets are reflected net of our allowance for doubtful accounts. We routinely review our receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such delays involve billing delays and discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. At December 31, 2002 approximately 99% of net accounts receivable classified as current were less than 60 days past scheduled invoice date and our allowance for doubtful accounts receivable classified as current totaled $3.1 million, representing 31% of all receivable balances greater than 60 days past the scheduled invoice date. At December 31, 2002 approximately $6.5 million of net accounts receivable were classified as long-term and our allowance for doubtful accounts receivable classified as long-term totaled $5.0 million representing 43% of all long-term receivable balances. 
 
During the first quarter of 2003 we continued our concerted effort to reconcile any remaining discrepancies with third parties and bring substantially all receivable balances to within sixty days of scheduled invoice date. During this period we resolved several issues and discrepancies, realized collections from various third parties and made corresponding adjustments to related receivable and payable balances. As a result, the aggregate balance of net accounts receivable balances classified as long-term was reduced by 54% to a remaining balance of $3.0 million at March 31, 2003. The net balance of receivables classified as current that were greater than 60 days past the scheduled invoice date were reduced by 13% and constituted approximately 1% of the total net accounts receivable balance classified as current. Our allowance for doubtful accounts receivable classified as 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 
 
(unaudited) 
 
current and long-term at March 31, 2003 totaled $3.1 million and $5.0 million, respectively, representing 34% and 63% of such respective gross balances. We believe the remaining net receivable balances greater than sixty days past scheduled invoice date are collectible or subject to offsets and consider our reserves adequate. However, since these obligations are not currently secured by letters of credit, in the event our counterparties experience an unanticipated deterioration in their credit-worthiness, any addition to existing reserves or write-offs in excess of such reserves would result in a charge to earnings. We do not believe any such charge would have a material effect on our cash flow or liquidity. 
 
Note 4—Partners’ Capital and Distributions 
 
In March 2003, we completed a public offering of 2,645,000 common units for $24.80 per unit. The offering resulted in cash proceeds of approximately $65.6 million from the sale of the units and approximately $1.3 million from our general partner’s proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $3.0 million. Net proceeds of approximately $63.9 million were used to reduce outstanding borrowings under the domestic revolving credit facility. 
 
On April 24, 2003, we declared a cash distribution of $0.55 per unit on our outstanding common units, Class B common units and subordinated units. The distribution is payable on May 15, 2003, to unitholders of record on May 5, 2003, for the period January 1, 2003, through March 31, 2003. The total distribution to be paid is approximately $30.6 million, with approximately $23.2 million to be paid to our common unitholders, $5.5 million to be paid to our subordinated unitholders and $0.6 million and $1.3 million to be paid to our general partner for its general partner and incentive distribution interests, respectively. The distribution is in excess of the minimum quarterly distribution specified in the partnership agreement. 
 
On January 24, 2003, we declared a cash distribution of $0.5375 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid on February 14, 2003, to unitholders of record on February 4, 2003, for the period October 1, 2002, through December 31, 2002. The total distribution paid was approximately $28.2 million, with approximately $21.2 million paid to our common unitholders, $5.4 million paid to our subordinated unitholders and $0.6 million and $1.0 million paid to our general partner for its general partner and incentive distribution interests, respectively. The distribution was in excess of the minimum quarterly distribution specified in the partnership agreement. 
 
Note 5—Derivative Instruments and Hedging Activities 
 
We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. 
 
Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX and over-the-counter positions, and physical volumes, grades, locations and delivery schedules to ensure that our hedging activities address our market risks. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 
 
(unaudited) 

Summary of Financial Impact 
 
The following is a summary of the financial impact of the derivative instruments and hedging activities discussed below. The March 31, 2003, balance sheet includes assets of $25.9 million ($24.4 million current), liabilities of $27.8 million ($14.9 million current) and related unrealized net losses deferred to Other Comprehensive Income (“OCI”) of $3.9 million. In addition, revenues for the three months ended March 31, 2003, included a noncash gain of $0.9 million ($1.9 million noncash gain before the reversal of the prior period fair value adjustment related to contracts that settled during the current period). Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet. 
 
As of March 31, 2003, the total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. During the three months ended March 31, 2003 and 2002, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Of the $3.9 million net loss deferred to OCI at March 31, 2003, a gain of $6.6 million will be reclassified to earnings in the next twelve months and the remainder by December 2005. Since these amounts are based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions. 
 
The following sections discuss our risk management activities in the indicated categories. 
 
Commodity Price Risk Hedging 
 
We hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments utilized consist primarily of futures and option contracts traded on the New York Mercantile Exchange and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies. In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” these derivative instruments are recognized in the balance sheet or earnings at their fair values. The majority of our commodity price risk derivative instruments qualify for hedge accounting as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into OCI and recognized in revenues or cost of sales and operations in the periods during which the underlying physical transactions occur. We have determined that our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133. At March 31, 2003 and 2002, there was a gain of $7.0 million and a loss of $5.3 million, respectively, deferred in OCI related to our commodity price risk activities. The amount included in earnings due to changes in the fair value of derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective for the three months ended March 31, 2003 and 2002, was a gain of $1.0 million and a loss of $2.9 million, respectively. 
 
Controlled Trading Program 
 
From time to time, we experience net unbalanced positions as a result of production and delivery variances associated with our lease purchase activities. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to 500,000 barrels. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 
 
(unaudited) 
 
in fair value recorded net in revenues. Although there were no open positions under this program at March 31, 2003 and 2002, the realized earnings impact related to these derivatives for the three months ended March 31, 2003 and 2002 was a loss of $0.1 million and $0.2 million, respectively. 
 
Interest Rate Risk Hedging 
 
We utilize various products, such as interest rate swaps, collars and treasury locks to hedge interest obligations on specific debt issuances, including anticipated debt issuances. During the first quarter of 2003, we converted a $50 million treasury lock into a 10-year LIBOR-based swap that becomes effective in March 2004, as discussed below, contemporaneously with the expiration of an existing $50 million LIBOR-based swap. The instruments outstanding at March 31, 2003, consist of three separate interest rate swaps with an aggregate notional principal amount of $100.0 million outstanding at any one time. The interest rate swaps are based on LIBOR rates and provide for a LIBOR rate of 5.1% for a $50.0 million notional principal amount expiring October 2006, a LIBOR rate of 4.3% for a $50.0 million notional principal amount expiring March 2004 and a LIBOR rate of 5.8% for a $50 million notional principal amount that commences in March 2004 and expires in March 2014. We believe all of these instruments are placed with large creditworthy financial institutions. Interest on the underlying debt is based on LIBOR plus a margin. 
 
These instruments qualify for hedge accounting as cash flow hedges in accordance with SFAS 133. The effective portion of changes in fair values of these hedges is recorded in OCI until the related hedged item impacts earnings. At March 31, 2003 and 2002, there were losses of $10.8 million and $2.7 million, respectively, deferred in OCI related to our interest rate risk activities. For the three months ended March 31, 2003 and 2002, there were no amounts recognized into earnings related to hedge ineffectiveness. 
 
At March 31, 2003, our average interest rate, excluding non-use and facilities fees, was approximately 6.2%. This rate is based on our March 31, 2003 debt balances and floating rate indices, our credit spread under our credit facilities and the combination of our fixed rate debt and current interest rate hedges. We have locked-in interest rates (excluding the credit spread under the credit facilities) for approximately 57% of our total long-term debt through October 2006, and 48% for the period from October 2006 through September 2012. 
 
Currency Exchange Rate Risk Hedging 
 
Since a significant portion of our Canadian business is conducted in Canadian dollars (CAD), we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include forward exchange contracts, forward extra option contracts and cross currency swaps. Additionally, at March 31, 2003, $1.4 million of our long-term debt was denominated in Canadian dollars ($2.1 million CAD based on a Canadian-U.S. dollar exchange rate of 1.47). 
 
At March 31, 2003, we had forward exchange contracts and forward extra option contracts that allow us to exchange $3.0 million Canadian for at least $1.9 million U.S. quarterly during 2003 (based on a Canadian-U.S. dollar exchange rate of 1.54). At March 31, 2003, we also had cross currency swap contracts for an aggregate notional principal amount of $24.8 million, effectively converting this amount of our senior secured term loan to $38.3 million of Canadian dollar debt (based on a Canadian-U.S. dollar exchange rate of 1.55). The terms of this contract mirror the term loan, matching the amortization schedule and final maturity in May 2006. We believe all of these financial instruments are placed with large creditworthy financial institutions. 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 
 
(unaudited) 

The forward exchange contracts and forward extra option contracts qualify for hedge accounting as cash flow hedges, in accordance with SFAS 133. Such derivative activity resulted in a loss of $0.1 million and a gain of $0.3 million deferred in OCI at March 31, 2003 and 2002, respectively. The cross currency swaps qualify for hedge accounting as fair value hedges, also in accordance with SFAS 133. The earnings impact related to our cross currency swaps was a loss of $0.1 million for the three months ended March 31, 2003 and a nominal amount for the three months ended March 31, 2002. 
 
Note 6—Commitments and Contingencies 
 
Export License Matter.    In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the short supply controls of the Export Administration Regulations (the “EAR”) and must be licensed by the Bureau of Industry and Security (the “BIS”) of the U.S. Department of Commerce. We have determined that we have exceeded the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of these potential violations. 
 
Litigation.    We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these other legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. 
 
Other.    Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets (including our nation’s pipeline infrastructure) may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. The Department of Transportation (“DOT”) has developed a security guidance document and has issued a security circular that defines critical pipeline facilities and appropriate countermeasures for protecting them, and explains how the DOT plans to verify that operators have taken appropriate action to implement satisfactory security procedures and plans. Using the guidelines provided by the DOT, we have specifically identified certain of our facilities as DOT “critical facilities” and therefore potential terrorist targets. In compliance with DOT guidance, we performed vulnerability analyses on our critical facilities and have instituted, or will institute as appropriate, any indicated security measures or procedures that are not already in place. The Transportation Safety Administration (an agency of the Department of Homeland Security, which is in the transitional phase of assuming responsibility from the DOT) may issue additional guidelines. We cannot assure you that these or any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not. 
 
We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. 
 
The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 
 
(unaudited) 
 
We believe that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. 
 
We are party to various contracts entered into in the ordinary course of business that contain indemnity provisions pursuant to which we indemnify the counterparties against various expenses. Our indemnity obligations are contingent upon the occurrence of events or circumstances specified in the contracts. No such events or circumstances have occurred at this time, and we do not consider our liability under such indemnity provisions, individually or in the aggregate, to be material to our financial position or results of operations. 
 
Note 7—Operating Segments 
 
Our operations consist of two operating segments: (1) our Pipeline Operations through which we engage in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; and (2) our Gathering, Marketing, Terminalling and Storage Operations through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on (i) gross margin (excluding depreciation), (ii) gross profit (excluding depreciation), which is gross margin (excluding depreciation) less general and administrative expenses and (iii) on an annual basis, maintenance capital. Maintenance capital consists of expenditures required to maintain the existing operating capacity of partially or fully depreciated assets or extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. 
 
 	  	Pipeline
	  	Gathering
Marketing,
Terminalling
& Storage
	  	Total
	
 	  	(in millions)	
Three Months Ended March 31, 2003	  	 	 	  	 	 	  	 	 	
Revenues:	  	 	 	  	 	 	  	 	 	
External Customers	  	$	159.0	  	$	3,122.9	  	$	3,281.9	
Intersegment (1)	  	 	10.0	  	 	0.2	  	 	10.2	
 	  			  			  			
Total revenues of reportable segments	  	$	169.0	  	$	3,123.1	  	$	3,292.1	
 	  			  			  			
Segment gross margin (excluding depreciation)	  	$	24.8	  	$	32.8	  	$	57.6	
General and administrative expenses (2)	  	 	4.6	  	 	8.5	  	 	13.1	
 	  			  			  			
Segment gross profit (excluding depreciation)	  	$	20.2	  	$	24.3	  	$	44.5	
 	  			  			  			
Noncash SFAS 133 impact (3)	  	$	—  	  	$	0.9	  	$	0.9	
 	  			  			  			
Maintenance capital	  	$	1.4	  	$	0.2	  	$	1.6	

	
 
Table continued on following page 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 
 
(unaudited) 
 
 	  	Pipeline
	  	Gathering
Marketing,
Terminalling
& Storage
	 	  	Total
	 	
 	  	(in millions)	 	
		
Three Months Ended March 31, 2002	  	 	 	  	 	 	 	  	 	 	 	
Revenues:	  	 	 	  	 	 	 	  	 	 	 	
External Customers	  	$	85.3	  	$	1,460.0	 	  	$	1,545.3	 	
Intersegment (1)	  	 	3.2	  	 	—  	 	  	 	3.2	 	
 	  			  				  				
Total revenues of reportable segments	  	$	88.5	  	$	1,460.0	 	  	$	1,548.5	 	
 	  			  				  				
Segment gross margin (excluding depreciation)	  	$	18.5	  	$	19.9	 	  	$	38.4	 	
General and administrative expenses (2)	  	 	3.3	  	 	7.5	 	  	 	10.8	 	
 	  			  				  				
Segment gross profit (excluding depreciation)	  	$	15.2	  	$	12.4	 	  	$	27.6	 	
 	  			  				  				
Noncash SFAS 133 impact (3)	  	$	—  	  	$	(2.9	)	  	$	(2.9	)	
 	  			  				  				
Maintenance capital	  	$	1.4	  	$	0.5	 	  	$	1.9	 	

(1)	 	Intersegment sales are based on published tariff rates or contracted amounts. 	
(2)	 	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. For comparison purposes, we have reclassified G&A by segment for the first quarter of 2002 to conform to the refined presentation used beginning in the third quarter of 2002. 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, segment gross margin (excluding depreciation) and segment gross profit (excluding depreciation). When we internally evaluate our results, we exclude the noncash, mark-to-market impact of SFAS 133. 	
 
Note 8—Recent Accounting Pronouncements 
 
In December 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 148 “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 in both annual and interim financial statements. SFAS 148 is effective for financial statements for fiscal years ending after December 15, 2002, and financial reports containing condensed financial statements for interim periods beginning after December 15, 2002. Our general partner has equity-based employee compensation plans. These plans are accounted for under the fair value based method as described in SFAS 123. Therefore, the adoption of this statement did not have a material effect on either our financial position, results of operations, cash flows or disclosure requirements. 
 
In June 2002, the FASB issued SFAS No. 146 “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the obligation is incurred rather than at the date of the exit plan. This Statement is effective for exit or disposal activities that are initiated after December 31, 2002. We have not initiated any material exit or disposal activities that are subject to this statement and do not believe that the adoption of SFAS 146 will have a material effect on either our financial position, results of operations or cash flows. 
 
In June 2001, the FASB issued SFAS No. 143 “Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the time of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to 
 
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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued) 
 
(unaudited) 
 
expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Effective January 1, 2003, we adopted SFAS 143, as required. Determination of the amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. The majority of our assets, primarily related to our pipeline operations segment, have obligations to perform remediation and, in some instances, removal 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. We will record such asset retirement obligations in the period in which we determine the settlement dates. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows. See Note 2 for the accounting treatment of the shutdown of the Rancho Pipeline System. 
 
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Item 2.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
 
Overview 
 
Plains All American Pipeline, L.P., is a publicly traded Delaware limited partnership (the “Partnership”) formed in 1998 and engaged in interstate and intrastate marketing, transportation and terminalling of crude oil and liquified petroleum gas (“LPG”). Our operations are conducted directly and indirectly through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana and the Canadian provinces of Alberta and Saskatchewan. 
 
During the first quarter of 2003, new Securities and Exchange Commission regulations regarding the use of non-GAAP financial measures became effective. As a result of our efforts to comply with these new regulations, we have made certain changes to the content and presentation of information in Management’s Discussion and Analysis of Financial Condition and Results of Operations. Although not excluded here, when we internally evaluate our results for performance against expectations, public guidance and trend analysis, we exclude the noncash, mark-to-market impact of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” resulting from (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. The majority of these instruments serve as economic hedges that offset future physical positions not reflected in current results. Therefore, the SFAS 133 adjustment to net income is not a complete depiction of the economic substance of the transaction, as it only represents the derivative side of these transactions and does not take into account the offsetting physical position. In addition, the impact will vary from quarter to quarter based on market prices at the end of the quarter, which are impossible for us to control or forecast. 
 
Internally, we also exclude from our operating results the impact of other items we consider to impact comparability between periods. To comply with the new regulations effective in March 2003, we have omitted certain adjustments and reconciliations related to these items that have been presented in the past. We have also changed the format of certain tables presented in the discussion of our results of operations. In addition, certain reclassifications have been made to prior period amounts to conform to current period presentation. Where appropriate, we have noted that reported results include the effects of items we consider to impact comparability between periods. Overall, we believe the discussion and presentation provides an accurate and thorough analysis of our results of operations and financial condition. Additionally, we will maintain on our website (www.paalp.com) a reconciliation of all non-GAAP financial information that we disclose to the most comparable GAAP measures. To access the information, investors should click on the “Non-GAAP Reconciliations” link on our home page. 
 
Acquisitions 
 
We completed several acquisitions during 2002 and 2003 that have impacted the results of operations and liquidity discussed herein. These acquisitions are discussed below and our ongoing acquisition activity is discussed further in “Liquidity and Capital Resources.” 
 
Red River Pipeline System 
 
In February 2003, we completed the acquisition of a 347-mile crude oil pipeline from BP Pipelines (North America) Inc. for approximately $19.3 million in cash, including transaction costs. The system originates at Sabine in East Texas and terminates near Cushing, Oklahoma. The system also includes approximately 695,000 barrels of crude oil storage capacity. We plan to replace approximately 32 miles of existing pipe on this pipeline and to build a twelve-mile extension of the system to connect to our terminal in Cushing. We estimate the total cost of the projects to be approximately $14.0 million, of which approximately $6.0 million will be spent in 
 
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2003 and approximately $8.0 million will be spent in 2004. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since February 1, 2003. The entire purchase price was allocated to property and equipment. This pipeline complements our existing assets in East Texas and, upon completion of the planned interconnect, will provide another direct mainline connection to our Cushing Terminal. 
 
Iatan Gathering System 
 
In March 2003, we completed the acquisition of a West Texas crude oil gathering system from Navajo Refining Company, L.P for approximately $24.3 million, including transaction costs. The assets are located in the Permian Basin in West Texas and consist of approximately 315 miles of active crude oil gathering lines. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2003. The entire purchase price was allocated to property and equipment. 
 
2002 Acquisitions 
 
In August 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 8.9 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the “Shell acquisition”) for approximately $324 million. In March 2002, we acquired substantially all of the domestic crude oil pipeline, gathering and marketing assets of Coast Energy Group and Lantern Petroleum, divisions of Cornerstone Propane Partners, L.P., for approximately $8.3 million. In February 2002, we acquired an approximate 22% equity interest in Butte Pipeline Company (the “Butte acquisition”) for approximately $7.6 million. 
 
Results of Operations 
 
For the three months ended March 31, 2003, we reported net income of $24.4 million on total revenues of $3.3 billion compared to net income for the same period in 2002 of $14.3 million on total revenues of $1.5 billion. Our net income includes a $0.9 million gain and a $2.9 million loss related to SFAS 133 for the quarters ended March 31, 2003 and 2002, respectively. 
 
Our operations consist of two operating segments: (1) our Pipeline Operations, through which we engage in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; and (2) our Gathering, Marketing, Terminalling and Storage Operations, through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on (i) gross margin (excluding depreciation), (ii) gross profit (excluding depreciation), which is gross margin (excluding depreciation) less general and administrative expenses and (iii) on an annual basis, maintenance capital. Maintenance capital consists of expenditures required to maintain the existing operating capacity of partially or fully depreciated assets or extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. For 2003, we have budgeted annual maintenance capital expenditures of $8.5 million. We monitor maintenance capital expenditures on an annual basis, since these capital projects can overlap quarters and may be impacted by weather, permitting and other non-controllable delays. Accordingly, no quarter by quarter analysis is provided. The following table reflects our results of operations for each segment: 
 
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 	  	Pipeline
Operations
	  	Gathering,
Marketing,
Terminalling &
Storage
	 	  	Total
	 	
 	  	(in millions)	 	
Three Months Ended March 31, 2003 (1)	  	 	 	  	 	 	 	  	 	 	 	
Revenues	  	$	169.0	  	$	3,123.1	 	  	$	3,292.1	 	
Cost of sales and operations (excluding depreciation)	  	 	144.2	  	 	3,090.3	 	  	 	3,234.5	 	
 	  			  				  				
Gross margin (excluding depreciation)	  	 	24.8	  	 	32.8	 	  	 	57.6	 	
General and administrative expenses (2)	  	 	4.6	  	 	8.5	 	  	 	13.1	 	
 	  			  				  				
Gross profit (excluding depreciation)	  	$	20.2	  	$	24.3	 	  	$	44.5	 	
 	  			  				  				
Noncash SFAS 133 impact (3)	  	$	—  	  	$	0.9	 	  	$	0.9	 	
 	  			  				  				
Maintenance capital	  	$	1.4	  	$	0.2	 	  	$	1.6	 	
 	  			  				  				
Three Months Ended March 31, 2002 (1)	  	 	 	  	 	 	 	  	 	 	 	
Revenues	  	$	88.5	  	$	1,460.0	 	  	$	1,548.5	 	
Cost of sales and operations (excluding depreciation)	  	 	70.0	  	 	1,440.1	 	  	 	1,510.1	 	
 	  			  				  				
Gross margin (excluding depreciation)	  	 	18.5	  	 	19.9	 	  	 	38.4	 	
General and administrative expenses (2)	  	 	3.3	  	 	7.5	 	  	 	10.8	 	
 	  			  				  				
Gross profit (excluding depreciation)	  	$	15.2	  	$	12.4	 	  	$	27.6	 	
 	  			  				  				
Noncash SFAS 133 impact (3)	  	$	—  	  	$	(2.9	)	  	$	(2.9	)	
 	  			  				  				
Maintenance capital	  	$	1.4	  	$	0.5	 	  	$	1.9	 	

(1)	 	Revenues and cost of sales and operations include intersegment amounts. 	
(2)	 	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 time. For comparison purposes, we have reclassified G&A expenses by segment for the first quarter of 2002 to conform to the refined presentation used beginning in the third quarter of 2002. 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, gross margin (excluding depreciation) and gross profit (excluding depreciation). 	
 
Pipeline Operations 
 
As adjusted for acquisitions completed in the first quarter of 2003 and the shut down of the Rancho Pipeline System which commenced in March 2003, we own and operate over 5,800 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting volumes of crude oil for a fee, third-party leases of pipeline capacity, barrel exchanges and buy/sell arrangements. We also use our pipelines in our merchant activities conducted under our gathering and marketing business. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The gross margin (excluding depreciation) generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable costs of operating the pipeline. Gross margin (excluding depreciation) from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount. 
 
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The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated: 
 
 	  	Three Months Ended
March 31,
	
 	  	2003
	  	2002
	
Operating Results (in millions) (1):	  	 	 	  	 	 	
Tariff activities revenues	  	$	33.8	  	$	20.7	
Merchant margin activities revenues	  	 	135.2	  	 	67.8	
 	  			  			
Total pipeline operations revenues	  	 	169.0	  	 	88.5	
Cost of sales and operations (excluding depreciation)	  	 	144.2	  	 	70.0	
 	  			  			
Gross margin (excluding depreciation)	  	 	24.8	  	 	18.5	
General & administrative expenses (2)	  	 	4.6	  	 	3.3	
 	  			  			
Gross profit (excluding depreciation)	  	$	20.2	  	$	15.2	
 	  			  			
Maintenance capital	  	$	1.4	  	$	1.4	
 	  			  			
Average Daily Volumes (thousands of barrels per day) (3):	  	 	 	  	 	 	
Tariff activities	  	 	 	  	 	 	
All American	  	 	59	  	 	67	
Basin	  	 	210	  	 	n/a	
Other domestic	  	 	269	  	 	152	
Canada	  	 	194	  	 	174	
 	  			  			
Total tariff activities	  	 	732	  	 	393	
Merchant margin activities	  	 	86	  	 	71	
 	  			  			
Total	  	 	818	  	 	464	

(1)	 	Revenues and cost of sales and operations include intersegment amounts. 	
(2)	 	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 time. For comparison purposes, we have reclassified G&A expenses by segment for the first quarter of 2002 to conform to the refined presentation used beginning in the third quarter of 2002. 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)	 	Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period. 	
 
Total average daily volumes transported were approximately 818,000 barrels per day and 464,000 barrels per day for the three months ended March 31, 2003 and 2002, respectively. As discussed above, we have completed a number of acquisitions during 2003 and 2002 that have impacted the results of operations herein. The following table reflects our total average daily volumes from our tariff activities by year of acquisition for comparison purposes: 
 
 	  	Three Months
Ended
March 31,
	
 	  	2003
	  	2002
	
Tariff Activities Average Daily Volumes (thousands of barrels per day) (1) (2):	  	 	  	 	
2003 acquisitions	  	14	  	—	
2002 acquisitions	  	331	  	9	
All other pipeline systems	  	387	  	384	
 	  		  		
Total tariff activities average daily volumes	  	732	  	393	

(1)	 	The 2003 acquisitions include the Red River pipeline system and the Iatan gathering system. The 2002 acquisitions include the pipeline systems included in the Shell acquisition and the Butte pipeline system. 	
(2)	 	Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period. 	
 
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Average daily volumes from our tariff activities were approximately 732,000 barrels per day compared to approximately 393,000 barrels per day for the prior year quarter. Approximately 336,000 barrels per day of the increase in the current year quarter is due to volumes transported on the pipelines acquired in 2003 and 2002, including approximately 316,000 on the assets acquired in the Shell acquisition. In addition, we transported approximately 20,000 barrels per day more on our Canadian pipelines in the current year quarter than in the prior year quarter. This increase in the first quarter of 2003 over the prior year quarter is due to the completion of capital expansion projects during 2002 that allowed for additional volumes on certain of our Canadian pipelines. The increase in volumes from our Canadian pipelines were substantially offset by decreases on various domestic pipeline systems including an approximate 8,000 barrel per day decrease in our All American tariff volumes attributable to California outer continental shelf (“OCS”) production. 
 
Total revenues from our pipeline operations were approximately $169.0 million and $88.5 million for the three months ended March 31, 2003 and 2002, respectively. The increase in revenues was primarily related to our merchant margin activities, which increased by approximately $67.4 million in the first quarter of 2003. This increase was primarily related to higher average prices on our merchant activity on our San Joaquin Valley gathering system in the 2003 period as compared to the 2002 period, but was also positively impacted by higher volumes on our buy/sell arrangements in the current period. However, this business is a margin business and although revenues and cost of sales are impacted by the absolute level of crude oil prices, there is a limited impact on gross margin. 
 
Revenues from our tariff activities increased approximately $13.1 million. The following table reflects our revenues from our tariff activities by year of acquisition for comparison purposes: 
 
 	  	Three Months
Ended
March 31,
	
 	  	2003
	  	2002
	
Tariff activities revenue (in millions) (1) (2):	  	 	 	  	 	 	
2003 acquisitions	  	$	1.2	  	$	—	
2002 acquisitions	  	 	12.2	  	 	0.1	
All other pipeline systems	  	 	20.4	  	 	20.6	
 	  			  			
Total tariff activities revenues	  	$	33.8	  	$	20.7	

(1)	 	Revenues include intersegment amounts. 	
(2)	 	The 2003 acquisitions include the Red River pipeline system and the Iatan gathering system. The 2002 acquisitions include the pipeline systems included in the Shell acquisition and the Butte pipeline system. 	
 
Total revenues from our tariff activities were approximately $33.8 million and $20.7 million for the three months ended March 31, 2003 and 2002, respectively. The increase in the first quarter of 2003 is predominately related to the inclusion of $13.4 million of revenues from the businesses acquired in 2003 and 2002, including approximately $12.1 million from the assets acquired in the Shell acquisition. Increased revenues resulting from increased volumes on our Canadian pipelines was offset by decreased revenues from the All American system on which we receive the highest per barrel tariffs among our pipeline operations. 
 
As a result of these factors, pipeline operations gross margin (excluding depreciation) increased 34% to approximately $24.8 million for the quarter ended March 31, 2003, from $18.5 million for the prior year period, an increase of approximately $6.3 million. 
 
General and administrative expenses increased approximately $1.3 million between comparable periods, as a result of acquisitions, our continued growth, and increased expenses related to corporate governance activities. Gross profit (excluding depreciation) was approximately $20.2 million in the first quarter of 2003, an increase of 33% as compared to the $15.2 million reported for the quarter ended March 31, 2002. Such results incorporate an 
 
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increase in operating expenses to $13.5 million in the 2003 period from $6.3 million in the 2002 period primarily related to acquisitions and our continued growth. 
 
Gathering, Marketing, Terminalling and Storage Operations 
 
Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased crude oil and liquefied petroleum gas (“LPG”) plus the sale of additional barrels exchanged through buy/sell arrangements entered into to enhance the margins of the gathered and bulk-purchased volumes. Gross margin from our gathering and marketing activities is dependent on our ability to sell crude oil and LPG at a price in excess of our aggregate cost. These operations are margin businesses and are not directly affected by the absolute level of prices, but are affected by overall levels of supply and demand for crude oil and LPG and fluctuations in market-related indices. Accordingly, an increase or decrease in revenues is not necessarily an indication of segment performance. 
 
We own and operate approximately 23.5 million barrels of above-ground crude oil terminalling and storage facilities, including a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to as the Cushing Interchange, is one of the largest crude oil market hubs in the United States and the designated delivery point for New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called “terminalling.” Approximately 11.0 million barrels of our 23.5 million barrels of tankage is used primarily in our Gathering, Marketing, Terminalling and Storage Operations and the balance is used in our Pipeline Operations segment. On a stand alone basis, gross margin from terminalling and storage activities is dependent on the throughput volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. Our terminalling and storage activities are integrated with our gathering and marketing activities and the level of tankage that we allocate for our arbitrage activities (and therefore not available for lease to third parties) varies throughout crude oil price cycles. This integration enables us to use our storage tanks to counter-cyclically balance and hedge our gathering and marketing activities. 
 
Crude oil prices have historically been very volatile and cyclical. Over the last 13 years, the NYMEX benchmark price has ranged from as high as $40.00 per barrel to as low as $10.00 per barrel. Our business strategy recognizes this volatility and the inherent inefficiencies such conditions create. Accordingly, we have deliberately configured our assets and integrated our activities in this segment to provide a counter-cyclical balance between our gathering and marketing activities and our terminalling and storage activities and execute different hedging strategies to stabilize and enhance margins and reduce the negative impact of crude oil market volatility. 
 
During the first quarter, market conditions were extremely volatile as a confluence of several events caused the NYMEX benchmark price of crude oil to range from as high as $39.99 per barrel to as low as $26.30 per barrel, with periods of steep backwardation throughout the first quarter of 2003 and the month or so preceding. These events included: (i) an oil workers strike in Venezuela, (ii) cold weather in the U.S. and Canada, (iii) low crude oil and refined product inventory levels and (iv) apprehension over U.S. military actions in Iraq. While this type of market does not provide economics for storing crude oil in our tanks, in conjunction with our hedging strategies it does enhance the returns of our gathering and marketing activities. During much of the first quarter of 2002, the crude oil market was in contango, which enhances the economics of storing crude oil and increases demand for storage services from third parties, but is generally disadvantageous for our gathering and marketing activities. 
 
As a result of completing our Phase II and Phase III expansions at our Cushing facility and acquisitions, total tankage dedicated to our gathering, marketing, terminalling and storage operations was approximately 5.0 million barrels greater in the first quarter of 2003 relative to the first quarter of 2002. A portion of such tankage was employed in hedging activities related to our gathering and marketing activities in the first quarter of 2003. 
 
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The following table sets forth our operating results from our Gathering, Marketing, Terminalling and Storage operations segment for the periods indicated: 
 
 	  	Three Months Ended
March 31,
	 	
 	  	2003
	  	2002
	 	
Operating Results (in millions) (1):	  	 	 	  	 	 	 	
Revenues	  	$	3,123.1	  	$	1,460.0	 	
Cost of sales and operations (excluding depreciation)	  	 	3,090.3	  	 	1,440.1	 	
 	  			  				
Gross margin (excluding depreciation)	  	 	32.8	  	 	19.9	 	
General & administrative expenses (2)	  	 	8.5	  	 	7.5	 	
 	  			  				
Gross profit (excluding depreciation)	  	$	24.3	  	$	12.4	 	
 	  			  				
Non cash SFAS 133 impact(3)	  	$	0.9	  	$	(2.9	)	
 	  			  				
Maintenance capital	  	$	0.2	  	$	0.5	 	
 	  			  				
Average Daily Volumes (thousands of barrels per day) (4):	  	 	 	  	 	 	 	
Crude oil lease gathering	  	 	434	  	 	399	 	
Crude oil bulk purchases	  	 	69	  	 	71	 	
 	  			  				
Total	  	 	503	  	 	470	 	
 	  			  				
LPG purchases	  	 	67	  	 	59	 	
 	  			  				
Cushing terminal throughput	  	 	175	  	 	64	 	
 	  			  				
Cushing Terminal storage leased to third parties, monthly average volumes	  	 	1,154	  	 	1,325	 	

(1)	 	Revenues and cost of sales and operations include intersegment amounts. 	
(2)	 	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 time. For comparison purposes, we have reclassified G&A expenses by segment for the first quarter of 2002 to conform to the refined presentation used beginning in the third quarter of 2002. 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, gross margin (excluding depreciation) and gross profit (excluding depreciation). 	
(4)	 	Volumes associated with acquisitions represent weighted averaged daily amounts for the number of days we actually owned the assets over the total days in the period. 	
 
Because of the overall counter-cyclical balance of our assets and the flexibility embedded in our business strategy, the benefit we received from the pronounced backwardation, volatile market conditions and increased tankage available to our gathering and marketing business in the first quarter of 2003 more than offset the adverse impact of reduced storage activities. During much of the first quarter of 2002, the crude oil market was in contango. Results in the first quarter of 2003 were further enhanced by increased sales and higher margins in our LPG activities resulting from cold weather throughout the U.S. and Canada. 
 
As a result of these factors, our gross margin (excluding depreciation) increased approximately $12.9 million or 65% to $32.8 million as compared to $19.9 million in the first quarter of 2002. These results include a $0.9 million noncash, mark-to-market gain pursuant to SFAS 133 in the 2003 quarterly period and a $2.9 million, SFAS 133 noncash, mark-to-market loss in the 2002 period. The impact of the SFAS 133 adjustments accounted for $3.8 million or approximately 29% of the increase in gross margin before depreciation. 
 
General and administrative expenses increased approximately $1.0 million between comparable periods, as a result of acquisitions, our continued growth and increased expenses related to corporate governance activities. Gross profit (excluding depreciation) was approximately $24.3 million in the first quarter of 2003, almost double the $12.4 million reported for the quarter ended March 31, 2002. The impact of the SFAS 133 adjustments accounted for $3.8 million or approximately 32% of the increase in gross profit before depreciation. 
 
As discussed previously, the majority of instruments we are required to mark-to-market at the end of each quarterly period pursuant to SFAS 133 do serve as economic hedges that offset future physical positions not 
 
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reflected in current results. Therefore, we believe mark-to-market adjustments to net income required under SFAS 133 do not provide a complete depiction of the economic substance of the transaction, as it only represents the derivative side of these transactions and does not take into account the offsetting physical position. Accordingly, when we internally evaluate our results for performance against expectations, public guidance and trend analysis, we exclude the non-cash, mark-to-market impact of SFAS 133 since the impact will vary from quarter to quarter based on market prices at the end of the quarter, which are impossible for us to control or forecast, and such SFAS 133 adjustments will reverse in future periods. Thus, we present the impact of the SFAS 133 adjustments because we believe such amounts impact the comparison of the fundamental operating results for the periods presented. 
 
In addition to market conditions and our hedging activities, the primary drivers of the performance of our gathering, marketing, terminalling and storage operations segment are crude oil lease gathered volumes and LPG purchase volumes. Crude oil bulk purchase volumes are not considered a driver as they are primarily used to enhance margins of lease gathered barrels. Gross profit per barrel (excluding depreciation) for the quarters ended March 31, 2003 and 2002, was $0.54 per barrel and $0.30 per barrel, respectively. 
 
For the quarter ended March 31, 2003, we gathered from producers, using our assets or third-party assets, approximately 434,000 barrels of crude oil per day, an increase of 9% over similar activities in the first quarter of 2002. In addition, we purchased in bulk, primarily at major trading locations, approximately 69,000 barrels of crude oil per day in the 2003 period and approximately 71,000 barrels per day in the 2002 period. Storage leased to third parties at our Cushing facility decreased to an average of 1.2 million barrels in the current year quarter from 1.3 million barrels in the first quarter of 2002. Terminal throughput volumes averaged approximately 175,000 barrels per day and 64,000 barrels per day for the quarter ended March 31, 2003 and 2002, respectively. Also during the quarter, we marketed approximately 67,000 barrels per day of LPG, an increase of approximately 15% over the approximately 59,000 barrels marketed in the first quarter of 2002. 
 
Revenues from our gathering, marketing, terminalling and storage operations were approximately $3.1 billion and $1.5 billion for the quarters ended March 31, 2003 and 2002, respectively. Revenues and cost of sales and operations (excluding depreciation) for 2003 were primarily impacted by higher average prices in the 2003 period as compared to the 2002 period. The average NYMEX price for crude oil was $33.87 per barrel and $21.67 per barrel for the first quarter of 2003 and 2002, respectively. 
 
Other Expenses 
 
Depreciation and Amortization 
 
Depreciation expense related to operations was approximately $9.3 million for the quarter ended March 31, 2003, compared to $5.9 million for the same period of 2002. Approximately $2.4 million of the increase is associated with the assets acquired in the Shell acquisition. The remainder of the increase is primarily related to the completion of various capital expansion projects. Depreciation and amortization expense related to general and administrative items increased approximately $0.5 million to $1.5 million in the first quarter of 2003 from the first quarter of 2002. The increase was related to an increase in debt issue costs related to the amendment of our credit facilities during 2002 and the sale of the senior unsecured notes in September 2002 as well as a number of various other items. Debt amortization costs included in depreciation and amortization expense were $1.0 million and $0.8 million in the first quarter of 2003 and 2002, respectively. 
 
Interest Expense 
 
Interest expense increased to $9.2 million for the quarter ended March 31, 2003, from $6.5 million for the comparable 2002 period. The increase is related to a higher average debt balance partially offset by lower interest rates. The higher average debt balance was primarily due to the portion of the Shell acquisition that was not financed with equity. 
 
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Outlook 
 
On April 25, 2003, we furnished Item 9 information in a current report on Form 8-K, containing guidance for operating and financial performance for the second quarter of 2003. 
 
Crude Oil Inventory.    We value our crude oil inventory at the lower of cost or market, with cost determined using an average cost method. At March 31, 2003 we had approximately 605,000 barrels of inventory classified as unhedged operating inventory at a weighted average cost of $28.82 per barrel. As noted above, crude oil prices have historically been very volatile. As an example, during the first quarter of 2003 the NYMEX averaged $33.87 per barrel, with a March 31, 2003 price of $31.04 per barrel. At April 30, 2003 the NYMEX crude oil price had declined to $25.80 per barrel. The lower of cost or market method requires a write down of inventory to the market price at the end of a period in which our weighted average cost exceeds the market price. This method does not allow a write up of the inventory if the market price subsequently increases. As the weighted average cost of our unhedged operating inventory was below the March 31, 2003 market price for such crude oil, we did not have an adjustment in this period. Future fluctuations in crude oil prices could result in a period end lower of cost or market adjustment. 
 
Acquisition Activities.    Consistent with our acquisition strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstream crude oil assets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. Since 1998, we have completed numerous acquisitions for an aggregate purchase price of approximately $1.2 billion. We can give you no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us. In connection with these activities, we routinely incur third party costs, which are capitalized and deferred pending final outcome of the transaction. Deferred costs associated with successful transactions are capitalized as part of the transaction, while deferred costs associated with unsuccessful transactions are expensed at the time of such final determination. At March 31, 2003, the amount of costs deferred pending final outcome was $0.3 million. 
 
Shutdown of Rancho Pipeline System.    The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, terminated in March 2003. Upon termination, the agreement requires the owners to take the pipeline system, in which we own an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not accept nominations for movements after February 28, 2003. The shutdown of the Rancho Pipeline System was contemplated by us at the time we made our acquisition proposal. The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. The ultimate use of the Rancho pipeline is still being evaluated by the owners, however, any value realized is expected to be minimal and relatively close to the purchase price allocated to this asset. At this time, we believe that increased movements on the Basin system, in which we own an approximate 87% interest, will substantially offset the lost margin associated with shutting down the Rancho system. 
 
Vesting of Unit Grants under Long-Term Incentive Plan.    Subject to additional vesting requirements, restricted units granted under our Long-Term Incentive Plan may vest in the same proportion as the conversion of our outstanding subordinated units into common units. Certain of the grants contain additional vesting requirements related to the Partnership achieving targeted distribution thresholds. Most of the grants also require additional passage of time before vesting occurs. Under generally accepted accounting principles, we are required to recognize an expense when the financial tests for conversion of subordinated units and required distribution levels are met. Thus, for at least some of the grants, recognition of expense may occur in a period prior to actual vesting and issuance of units to satisfy the grants. The expense will be a non-cash charge to the extent units are issued to satisfy the grants. 
 
At the current distribution level, assuming the subordination conversion test is met, the costs associated with the vesting of approximately 845,000 restricted units would be incurred or accrued in the second half of 2003 or 
 
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the first quarter of 2004. The timing of the vesting and the amount of the charge are subject to various factors, including the unit price on the date vesting occurs, and thus are not known at this time. Based on an assumed market price of $27.00 per unit, the aggregate charge associated with this vesting, including the partnership’s employer-related taxes, is approximately $24 million. To the extent such obligations are satisfied through the issuance of new units, there would be a corresponding increase in partners’ equity. 
 
Liquidity and Capital Resources 
 
Liquidity 
 
Cash generated from operations and our credit facilities are our primary sources of liquidity. At March 31, 2003, we had a working capital deficit of approximately $4.6 million, approximately $423.4 million of availability under our revolving credit facility and $107.7 million of availability under the letter of credit and hedged inventory facility. Usage of the credit facilities is subject to compliance with covenants. At March 31, 2003, we had received approximately $45.9 million of advance cash payments from third parties to mitigate credit risk. These proceeds were used to reduce long-term borrowings. 
 
We funded the purchase of the Red River and Iatan acquisitions with funds drawn on our revolving credit facilities. In March, we completed a public offering of 2,645,000 common units priced at $24.80 per unit. Net proceeds from the offering, including our general partner’s proportionate capital contribution and expenses associated with the offering, were approximately $63.9 million and were used to pay down our revolving credit facilities. 
 
We believe that we have sufficient liquid assets, cash from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely effect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity. 
 
Cash Flows 
 
 	  	Three Months Ended
March 31,
	 	
 	  	2003
	 	  	2002
	 	
 	  	(in millions)	 	
Cash provided by (used in):	  	 	 	 	  	 	 	 	
Operating activities	  	$	91.4	 	  	$	9.1	 	
Investing activities	  	 	(58.9	)	  	 	(24.5	)	
Financing activities	  	 	(30.9	)	  	 	15.1	 	
 
Operating Activities.    Net cash provided by operating activities for the three months ended March 31, 2003 was $91.4 million as compared to $9.1 million in the 2002 period. Cash provided by operating activities in the current quarter consisted primarily of (i) net income of $24.4 million, (ii) depreciation and amortization of $10.9 million and (iii) net changes in assets and liabilities of approximately $57.1 million. Cash provided by operating activities in the prior year quarter consisted primarily of (i) net income of $14.3 million, (ii) depreciation and amortization of $7.0 million, (iii) a change in derivative fair value related to SFAS 133 of $2.9 million and (iv) net cash used in operating activities from changes in assets and liabilities of approximately $15.0 million. The net changes in assets and liabilities are generally the result of the timing of cash receipts related to sales and cash disbursements related to purchases, inventory and other expenses. 
 
Investing Activities.    Net cash used in investing activities in 2003 includes approximately $43.4 million paid for the Red River and Iatan acquisitions. Investing activities also includes approximately $15.1 million for construction of crude oil gathering and transmission lines in West Texas, the completion of the Cushing 
 
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expansion and other capital projects. Net cash used in investing activities in 2002 includes $13.2 million for the Butte and Coast/Lantern acquisitions and $11.4 million of capital expenditures primarily for the Cushing expansion and other capital projects. 
 
Financing Activities.    Cash provided by financing activities in 2003 consisted of approximately $63.9 million of proceeds from the issuance of common units used to pay down outstanding balances on the revolving credit facility. In addition, $28.2 million of distributions were paid to unitholders and the general partner during the three months ended March 31, 2003. Cash provided by financing activities in 2002 consisted primarily of net long-term borrowings of $39.3 million used primarily to fund capital expenditures. In addition, $23.2 million of distributions were paid to unitholders and the general partner. 
 
Universal Shelf 
 
We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue from time to time up to an aggregate of $700 million of debt or equity securities. At March 31, 2003, we have approximately $355 million remaining under this registration statement. 
 
Contingencies 
 
Litigation.    We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. 
 
Other.    Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets (including our nation’s pipeline infrastructure) may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. The Department of Transportation (“DOT)” has developed a security guidance document and has issued a security circular that defines critical pipeline facilities and appropriate countermeasures for protecting them, and explains how the DOT plans to verify that operators have taken appropriate action to implement satisfactory security procedures and plans. Using the guidelines provided by the DOT, we have specifically identified certain of our facilities as DOT “critical facilities” and therefore potential terrorist targets. In compliance with DOT guidance, we performed vulnerability analyses on our critical facilities and have instituted, or will institute as appropriate, any indicated security measures or procedures that are not already in place. The Transportation Safety Administration (an agency of the Department of Homeland Security, which is in the transitional phase of assuming responsibility from the DOT) may issue additional guidelines. We cannot assure you that these or any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not. 
 
We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. 
 
Industry Credit Markets and Accounts Receivable 
 
Throughout the latter part of 2001 and all of 2002, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and extreme financial distress at several large, diversified energy companies, the energy industry has been especially impacted by these developments. Accordingly, we are exposed to an increased level of direct and indirect counterparty credit and performance risk. 
 
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Our accounts receivable are primarily from purchasers and shippers of crude oil. The majority of our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. We make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided in the form of standby letters of credit. 
 
Accounts receivable included in the consolidated balance sheets are reflected net of our allowance for doubtful accounts. We routinely review our receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such delays involve billing delays and discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. At December 31, 2002 approximately 99% of net accounts receivable classified as current were less than 60 days past scheduled invoice date and our allowance for doubtful accounts receivable classified as current totaled $3.1 million, representing 31% of all receivable balances greater than 60 days past the scheduled invoice date. At December 31, 2002 approximately $6.5 million of net accounts receivable were classified as long-term and our allowance for doubtful accounts receivable classified as long-term totaled $5.0 million representing 43% of all long-term receivable balances. 
 
During the first quarter of 2003 we continued our concerted effort to reconcile any remaining discrepancies with third parties and bring substantially all receivable balances to within sixty days of scheduled invoice date. During this period we resolved several issues and discrepancies, realized collections from various third parties and made corresponding adjustments to related receivable and payable balances. As a result, the aggregate balance of net accounts receivable balances classified as long-term was reduced by 54% to a remaining balance of $3.0 million at March 31, 2003. As adjusted for transfers from long-term, the net balance of receivables classified as current that were greater than 60 days past the scheduled invoice date were reduced by 13% and constituted approximately 1% of the total net accounts receivable balance classified as current. Our allowance for doubtful accounts receivable classified as current and long-term at March 31, 2003 totaled $3.1 million and $5.0 million, respectively, representing 34% and 63% of such respective gross balances. We believe the remaining net receivable balances greater than sixty days past scheduled invoice date are collectible or subject to offsets and consider our reserves adequate. However, since these obligations are not currently secured by letters of credit, in the event our counterparties experience an unanticipated deterioration in their credit-worthiness, any addition to existing reserves or write-offs in excess of such reserves would result in a charge to earnings. We do not believe any such charge would have a material effect on our cash flow or liquidity. 
 
Recent Accounting Pronouncements 
 
We continuously monitor and revise our accounting policies as our business and relevant accounting literature change. At this time, there are several new accounting pronouncements that have recently been issued which will impact our accounting or disclosure, as they become effective. For further discussion of new accounting rules, see Item 1. Consolidated Financial Statements—Note 8 “Recent Accounting Pronouncements.” 
 
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 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 the All American Pipeline; 	
 
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 	•	 	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, 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. 	
 
Other factors, such as the “Risk Factors Related to our Business” and the Recent Disruption in Industry Credit Markets discussed in Item 7 of our most recent annual report on Form 10-K or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. 
 
Item 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS 
 
The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risks included in Item 7A. in our 2002 Form 10-K. There have not been any material changes in that information other than those discussed below. 
 
As of March 31, 2003 and December 31, 2002 the fair value of our crude oil futures contracts was approximately $8.3 million and $0.6 million respectively. A 10% price decrease would result in a decrease in fair value of $6.5 million and $4.3 million at March 31, 2003 and December 31, 2002, respectively. 
 
During the first quarter of 2003, we converted a $50 million treasury lock into a 10-year LIBOR based swap that becomes effective in March 2004, contemporaneously with the expiration of an existing $50 million LIBOR based swap. At March 31, 2003 the fair value of our interest rate risk hedging instruments was a liability of approximately $10.7 million with $1.5 million maturing in 2004, $4.7 million in 2006 and $4.5 million in 2014. 
 
As of March 31, 2003, the fair value of our currency exchange risk hedging instruments was a liability of approximately $1.8 million with $0.2 million maturing during 2003 and the remainder in 2006. 
 
Item 4.    CONTROLS AND PROCEDURES 
 
We maintain written “disclosure controls and procedures,” which we refer to as our “DCP.” The purpose of our DCP is to ensure that (i) information is recorded, processed, summarized and reported in time to allow for 
 
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timely disclosure of such information in accordance with the securities laws and SEC regulations and (ii) information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure. Our DCP is incremental to our system of internal accounting controls designed to comply with the requirements of Section 13(b)(2) of the Exchange Act. 
 
Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP, within the 90-day period prior to filing any 10-Q or 10-K, under the supervision and with the participation of our management, including our Chief Executive Office and Chief Financial Officer. Management (including our Chief Executive Officer and Chief Financial Officer) has evaluated the effectiveness of the design and operation of our DCP within the last 90 days, and have found our DCP to be effective in producing the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure. 
 
In addition to the information concerning our DCP, we are required to discuss significant changes in our internal controls. There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the last date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. 
 
We have recently consolidated our internal auditing activities into a centralized function. As we complete the first annual cycle under this centralized approach, we will make any additional enhancements to our controls and procedures that are deemed appropriate. 
 
The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. § 1350 accompany this report as exhibits 99.1 and 99.2. 
 
PART II. OTHER INFORMATION 
 
Item 1.    LEGAL PROCEEDINGS 
 
We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. 
 
Item 2.    CHANGES IN SECURITIES AND USE OF PROCEEDS 
 
None 
 
Item. 3.    DEFAULTS UPON SENIOR SECURITIES 
 
None 
 
Item 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
 
None 
 
Item 5.    OTHER INFORMATION 
 
None 
 
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Item 6.    EXHIBITS AND REPORTS ON FORM 8-K 
 
A.    Exhibits 
 
99.1    Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350. 
 
99.2    Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350 
 
B.    Reports on Form 8-K. 
 
A current report on Form 8-K was furnished on April 25, 2003, in connection with disclosure of second quarter estimates and earnings guidance. 
 
A current report on Form 8-K was furnished on April 25, 2003, in connection with disclosure of our presentation to the Independent Petroleum Association of America’s Oil and Gas Investment Symposium. 
 
A current report on Form 8-K was filed on March 6, 2003, including as an exhibit an underwriting agreement with Goldman, Sachs & Co. and A.G. Edwards and Sons, Inc. in connection with the sale by the Partnership of 2,300,000 common units of the Partnership. 
 
A current report on Form 8-K was filed on March 5, 2003, including as an exhibit the audited balance sheet of Plains AAP, L.P. as of December 31, 2002. 
 
A current report on Form 8-K was furnished on March 3, 2003, in connection with disclosure of our presentation to the Master Limited Partnership Investor Conference. 
 
A current report on Form 8-K was furnished on February 26, 2003, in connection with disclosure of first quarter estimates and earnings guidance. 

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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 and thereunto 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 2, 2003 
By:    /s/    GREG L. ARMSTRONG 
                                                                                         
Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of Plains 
All American GP LLC (Principal Executive 
    Officer) 
 
Date:    May 2, 2003 
By:    /s/    PHIL KRAMER 
                                                                                         
Phil Kramer, Executive Vice President and Chief Financial Officer 
(Principal Financial and Accounting Officer) 
 
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CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER 
 
PLAINS ALL AMERICAN PIPELINE, L.P. 
 
I, Greg L. Armstrong, certify that: 
 
 	1.	 	I have reviewed this quarterly report on Form 10-Q of Plains All American Pipeline, L.P.; 	
 
 	2.	 	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 	
 
 	3.	 	Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 	
 
 	4.	 	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: 	
 
 	a)	 	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; 	
 
 	b)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and 	
 
 	c)	 	presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 	
 
 	5.	 	The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function): 	
 
 	a)	 	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and 	
 
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and 	
 
 	6.	 	The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. 	
 
Date:    May 2, 2003 
 
/s/    GREG L. ARMSTRONG 
                                                                                                          
Greg L. Armstrong 
Chief Executive Officer 

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CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER 
 
PLAINS ALL AMERICAN PIPELINE, L.P. 
 
I, Phil Kramer, certify that: 
 
 	1.	 	I have reviewed this quarterly report on Form 10-Q of Plains All American Pipeline, L.P.; 	

 	2.	 	Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 	

 	3.	 	Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 	

 	4.	 	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: 	

 	a)	 	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; 	
 
 	b)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and 	
 
 	c)	 	presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 	
 
 	5.	 	The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function): 	
 
 	a)	 	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and 	
 
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and 	
 
 	6.	 	The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. 	
 
Date:    May 2, 2003 
 
/s/    PHIL KRAMER 
                                                                                                          
Phil Kramer 
Chief Financial Officer 

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EXHIBIT 99.1 
 
CERTIFICATION OF 
CHIEF EXECUTIVE OFFICER 
OF PLAINS ALL AMERICAN PIPELINE, L.P. 
PURSUANT TO 18 U.S.C. § 1350 
 
I, Greg L. Armstrong, Chief Executive Officer of Plains All American Pipeline, L.P. (the “Company”), hereby certify that: 
 
 	(i)	 	the accompanying report on Form 10-Q for the period ending March 31, 2003 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) by the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and 	
 
 	(ii)	 	the information contained in the Report fairly presents, in all material respects, the financial operations and results of operations of the Company. 	

/s/ GREG L. ARMSTRONG

Name:    Greg L. Armstrong
Date:     May 2, 2003 	
 
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. 
 
EXHIBIT 99.2 
 
CERTIFICATION OF 
CHIEF FINANCIAL OFFICER 
OF PLAINS ALL AMERICAN PIPELINE, L.P. 
PURSUANT TO 18 U.S.C. § 1350 
 
I, Phil Kramer, Chief Financial Officer of Plains All American Pipeline, L.P. (the “Company”), hereby certify that: 
 
 	(i)	 	the accompanying report on Form 10-Q for the period ending March 31, 2003 and filed with the Securities and Exchange Commission on the date hereof (the “Report”) by the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and 	
 
 	(ii)	 	the information contained in the Report fairly presents, in all material respects, the financial operations and results of operations of the Company. 	
 
/s/ PHIL KRAMER	

Name:    Phil Kramer
Date:     May 2, 2003 	
 
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.