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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES TABLE OF CONTENTS

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 June 30, 2004	

OR	

o	
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
(State or other jurisdiction of
incorporation or organization)	 	76-0582150
(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 o 
        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ☒    No o 
        At August 5, 2004, there were outstanding 62,628,722 Common Units, 1,307,190 Class B Common Units and 3,245,700 Class C Common Units. 

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 

TABLE OF CONTENTS 

PART I. FINANCIAL INFORMATION	

Item 1. CONSOLIDATED FINANCIAL STATEMENTS:	
Consolidated Balance Sheets:	
 	June 30, 2004 and December 31, 2003	
Consolidated Statements of Operations:	
 	For the three months and six months ended June 30, 2004 and 2003	
Consolidated Statements of Cash Flows:	
 	For the six months ended June 30, 2004 and 2003	
Consolidated Statement of Partners' Capital:	
 	For the six months ended June 30, 2004	
Consolidated Statements of Comprehensive Income:	
 	For the three and six months ended June 30, 2004 and 2003	
Consolidated Statement of Changes in Accumulated Other Comprehensive Income:	
 	For the six months ended June 30, 2004	
Notes to the Consolidated Financial Statements	
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS	
Item 4. CONTROLS AND PROCEDURES	

PART II. OTHER INFORMATION	

Item 1. Legal Proceedings	
Item 2. Changes in Securities and Use of Proceeds	
Item 3. Defaults Upon Senior Securities	
Item 4. Submission of Matters to a Vote of Security Holders	
Item 5. Other Information	
Item 6. Exhibits and Reports on Form 8-K	
Signatures	
2

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) 
 	 	June 30,
2004
	 	December 31,
2003
	 	
 	 	(unaudited)	 	
ASSETS	 	 	 	 	 	 	 	

CURRENT ASSETS	

 	

 	
 	
Cash and cash equivalents	 	$	12,056	 	$	4,137	 	
Trade accounts receivable, net	 	 	645,295	 	 	590,645	 	
Inventory	 	 	128,534	 	 	105,967	 	
Other current assets	 	 	43,564	 	 	32,225	 	
 	 		 		 	
 	Total current assets	 	 	829,449	 	 	732,974	 	
 	 		 		 	
PROPERTY AND EQUIPMENT	 	 	1,730,496	 	 	1,272,634	 	
Accumulated depreciation	 	 	(147,949	)	 	(121,595	)	
 	 		 		 	
 	 	 	1,582,547	 	 	1,151,039	 	
 	 		 		 	
OTHER ASSETS	 	 	 	 	 	 	 	
Pipeline linefill in owned assets	 	 	148,680	 	 	95,928	 	
Inventory in third party assets	 	 	38,745	 	 	26,725	 	
Other, net	 	 	82,483	 	 	88,965	 	
 	 		 		 	
 	Total assets	 	$	2,681,904	 	$	2,095,631	 	
 	 		 		 	
LIABILITIES AND PARTNERS' CAPITAL	 	 	 	 	 	 	 	

CURRENT LIABILITIES	

 	

 	
 	
Accounts payable	 	$	763,659	 	$	603,460	 	
Due to related parties	 	 	27,195	 	 	26,981	 	
Short-term debt	 	 	21,989	 	 	127,259	 	
Other current liabilities	 	 	42,803	 	 	44,219	 	
 	 		 		 	
 	Total current liabilities	 	 	855,646	 	 	801,919	 	
 	 		 		 	
LONG-TERM LIABILITIES	 	 	 	 	 	 	 	
Long-term debt under credit facilities	 	 	485,774	 	 	70,000	 	
Senior notes, net of unamortized discount of $957 and $1,009, respectively	 	 	449,043	 	 	448,991	 	
Other long-term liabilities and deferred credits	 	 	25,922	 	 	27,994	 	
 	 		 		 	
 	Total liabilities	 	 	1,816,385	 	 	1,348,904	 	
 	 		 		 	
COMMITMENTS AND CONTINGENCIES (NOTE 9)	 	 	 	 	 	 	 	

PARTNERS' CAPITAL	

 	

 	
 	
Common unitholders (57,724,722 and 49,502,556 units outstanding at June 30, 2004, and December 31, 2003, respectively)	 	 	722,110	 	 	744,073	 	
Class B common unitholder (1,307,190 units outstanding at each date)	 	 	17,951	 	 	18,046	 	
Class C common unitholders (3,245,700 units and no units outstanding at June 30, 2004, and December 31, 2003, respectively)	 	 	98,297	 	 	—	 	
Subordinated unitholders (no units and 7,522,214 units outstanding at June 30, 2004, and December 31, 2003, respectively)	 	 	—	 	 	(39,913	)	
General partner	 	 	27,161	 	 	24,521	 	
 	 		 		 	
 	Total partners' capital	 	 	865,519	 	 	746,727	 	
 	 		 		 	
 	Total liabilities and partners' capital	 	$	2,681,904	 	$	2,095,631	 	
 	 		 		 	
The accompanying notes are an integral part of these consolidated financial statements. 
3

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF OPERATIONS 

(in thousands, except per unit data) 
 	 	Three Months Ended
June 30,
	 	Six Months Ended
June 30,
	 	
 	 	2004
	 	2003
	 	2004
	 	2003
	 	
 	 	(unaudited)	 	(unaudited)	 	
REVENUES	 	 	 	 	 	 	 	 	 	 	 	 	 	
Crude oil and LPG sales	 	$	4,939,467	 	$	2,557,284	 	$	8,555,451	 	$	5,672,571	 	
Other gathering, marketing, terminalling and storage revenues	 	 	1,608	 	 	8,608	 	 	16,727	 	 	15,957	 	
Pipeline margin activities revenues	 	 	138,831	 	 	117,515	 	 	281,166	 	 	252,686	 	
Pipeline tariff activities revenues	 	 	51,829	 	 	25,782	 	 	83,035	 	 	49,883	 	
 	 		 		 		 		 	
 	Total revenues	 	 	5,131,735	 	 	2,709,189	 	 	8,936,379	 	 	5,991,097	 	

COSTS AND EXPENSES	

 	

 	

 	

 	
 	
Crude oil and LPG purchases and related costs	 	 	4,859,173	 	 	2,508,709	 	 	8,416,244	 	 	5,569,420	 	
Pipeline margin activities purchases	 	 	132,694	 	 	112,601	 	 	269,128	 	 	243,131	 	
Field operating costs (excluding LTIP charge)	 	 	59,035	 	 	32,574	 	 	96,851	 	 	65,689	 	
LTIP charge—operations	 	 	—	 	 	—	 	 	567	 	 	—	 	
General and administrative expenses (excluding LTIP charge)	 	 	19,603	 	 	12,161	 	 	35,081	 	 	25,233	 	
LTIP charge—general and administrative	 	 	—	 	 	—	 	 	3,661	 	 	—	 	
Depreciation and amortization	 	 	15,998	 	 	11,305	 	 	29,118	 	 	22,176	 	
 	 		 		 		 		 	
 	Total costs and expenses	 	 	5,086,503	 	 	2,677,350	 	 	8,850,650	 	 	5,925,649	 	
 	 		 		 		 		 	
OPERATING INCOME	 	 	45,232	 	 	31,839	 	 	85,729	 	 	65,448	 	
 	 		 		 		 		 	
OTHER INCOME/(EXPENSE)	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense (net of $219 and $244 capitalized for the three month periods, respectively, and $397 and $296 capitalized for the six month periods, respectively)	 	 	(9,967	)	 	(8,532	)	 	(19,499	)	 	(17,686	)	
Interest and other income (expense), net	 	 	412	 	 	91	 	 	453	 	 	(13	)	
 	 		 		 		 		 	
Income before cumulative effect of change in accounting principle	 	 	35,677	 	 	23,398	 	 	66,683	 	 	47,749	 	
Cumulative effect of change in accounting principle	 	 	—	 	 	—	 	 	(3,130	)	 	—	 	
 	 		 		 		 		 	
NET INCOME	 	$	35,677	 	$	23,398	 	$	63,553	 	$	47,749	 	
 	 		 		 		 		 	
NET INCOME-LIMITED PARTNERS	 	$	33,247	 	$	21,690	 	$	58,954	 	$	44,566	 	
 	 		 		 		 		 	
NET INCOME-GENERAL PARTNER	 	$	2,430	 	$	1,708	 	$	4,599	 	$	3,183	 	
 	 		 		 		 		 	
BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income before cumulative effect of change in accounting principle	 	$	0.54	 	$	0.42	 	$	1.03	 	$	0.87	 	
Cumulative effect of change in accounting principle	 	 	—	 	 	—	 	 	(0.05	)	 	—	 	
 	 		 		 		 		 	
Net income	 	$	0.54	 	$	0.42	 	$	0.98	 	$	0.87	 	
 	 		 		 		 		 	
WEIGHTED AVERAGE UNITS OUTSTANDING	 	 	61,556	 	 	52,223	 	 	59,985	 	 	51,200	 	
 	 		 		 		 		 	
The accompanying notes are an integral part of these consolidated financial statements. 
4

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

(in thousands) 
 	 	Six Months Ended
June 30,
	 	
 	 	2004
	 	2003
	 	
 	 	(unaudited)	 	
CASH FLOWS FROM OPERATING ACTIVITIES	 	 	 	 	 	 	 	
Net income	 	$	63,553	 	$	47,749	 	
Adjustments to reconcile to cash flows from operating activities:	 	 	 	 	 	 	 	
 	Depreciation and amortization	 	 	29,118	 	 	22,176	 	
 	Cumulative effect of change in accounting principle	 	 	3,130	 	 	 	 	
 	Change in derivative fair value	 	 	(556	)	 	(1,155	)	
 	Noncash portion of LTIP charge	 	 	4,228	 	 	—	 	
 	Noncash amortization of terminated interest rate swap	 	 	714	 	 	—	 	
Changes in assets and liabilities, net of acquisitions:	 	 	 	 	 	 	 	
 	Accounts receivable and other	 	 	(28,575	)	 	52,402	 	
 	Inventory	 	 	(24,135	)	 	41,015	 	
 	Accounts payable and other current liabilities	 	 	99,423	 	 	35,718	 	
 	Settlement of environmental indemnities	 	 	—	 	 	4,600	 	
 	Due to related parties	 	 	210	 	 	2,292	 	
 	 		 		 	
 	 	Net cash provided by operating activities	 	 	147,110	 	 	204,797	 	
 	 		 		 	
CASH FLOWS FROM INVESTING ACTIVITIES	 	 	 	 	 	 	 	
Cash paid in connection with acquisitions (Note 2)	 	 	(443,210	)	 	(79,616	)	
Additions to property and equipment	 	 	(32,170	)	 	(37,492	)	
Cash paid for linefill on assets owned	 	 	—	 	 	(28,478	)	
Proceeds from sales of assets	 	 	737	 	 	5,790	 	
 	 		 		 	
 	 	Net cash used in investing activities	 	 	(474,643	)	 	(139,796	)	
 	 		 		 	
CASH FLOWS FROM FINANCING ACTIVITIES	 	 	 	 	 	 	 	
Net borrowings on long-term revolving credit facility	 	 	415,827	 	 	29,089	 	
Net repayments on working capital revolving credit facility	 	 	(12,100	)	 	—	 	
Net repayments on short-term letter of credit and hedged inventory facility	 	 	(96,091	)	 	(90,178	)	
Net borrowings on other short-term debt	 	 	(1,641	)	 	—	 	
Principal payments on senior secured term loan	 	 	—	 	 	(7,000	)	
Cash paid in connection with financing arrangements	 	 	(500	)	 	(60	)	
Net proceeds from the issuance of common units	 	 	101,213	 	 	63,895	 	
Distributions paid to unitholders and general partner	 	 	(72,673	)	 	(58,772	)	
 	 		 		 	
 	 	Net cash provided by (used in) financing activities	 	 	334,035	 	 	(63,026	)	

Effect of translation adjustment on cash	

1,417	

94	

Net increase in cash and cash equivalents	

7,919	

2,069	
 	
Cash and cash equivalents, beginning of period	 	 	4,137	 	 	3,501	 	
 	 		 		 	
Cash and cash equivalents, end of period	 	$	12,056	 	$	5,570	 	

Cash paid for interest, net of amounts capitalized	
 	
$	
20,547	
 	
$	
19,092	

The accompanying notes are an integral part of these consolidated financial statements. 
5

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL 

(in thousands) 
 	 	Common Units
	 	Class B
Common Units
	 	Class C
Common Units
	 	Subordinated Units
	 	General
Partner
	 	Total
Partners'
Capital
	 	
 	 	Units
	 	Amount
	 	Units
	 	Amount
	 	Units
	 	Amount
	 	Units
	 	Amount
	 	Amount
	 	Amount
	 	
 	 	(unaudited)	 	
Balance at December 31, 2003	 	49,502	 	$	744,073	 	1,307	 	$	18,046	 	—	 	$	—	 	7,523	 	$	(39,913	)	$	24,521	 	$	746,727	 	
Issuance of common
units under LTIP	 	315	 	 	10,250	 	—	 	 	—	 	—	 	 	—	 	—	 	 	—	 	 	208	 	 	10,458	 	
Private placement of Class C common units	 	—	 	 	—	 	—	 	 	—	 	3,246	 	 	98,831	 	—	 	 	—	 	 	2,041	 	 	100,872	 	
Payment of deferred acquisition price	 	385	 	 	13,082	 	—	 	 	—	 	—	 	 	—	 	—	 	 	—	 	 	267	 	 	13,349	 	
Distributions	 	—	 	 	(60,363	)	—	 	 	(1,470	)	—	 	 	(1,826	)	—	 	 	(4,231	)	 	(4,783	)	 	(72,673	)	
Other comprehensive income	 	—	 	 	3,604	 	—	 	 	84	 	—	 	 	78	 	—	 	 	(841	)	 	308	 	 	3,233	 	
Net income	 	—	 	 	55,005	 	—	 	 	1,291	 	—	 	 	1,214	 	—	 	 	1,444	 	 	4,599	 	 	63,553	 	
Conversion of subordinated units	 	7,523	 	 	(43,541	)	—	 	 	—	 	—	 	 	—	 	(7,523	)	 	43,541	 	 	—	 	 	—	 	
 	 		 		 		 		 		 		 		 		 		 		 	
Balance at June 30,
2004	 	57,725	 	$	722,110	 	1,307	 	$	17,951	 	3,246	 	$	98,297	 	—	 	$	—	 	$	27,161	 	$	865,519	 	
 	 		 		 		 		 		 		 		 		 		 		 	
The accompanying notes are an integral part of these consolidated financial statements. 
6

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
June 30,
	 	Six Months Ended
June 30,
	
 	 	2004
	 	2003
	 	2004
	 	2003
	
 	 	(unaudited)	 	(unaudited)	
Net income	 	$	35,677	 	$	23,398	 	$	63,553	 	$	47,749	
Other comprehensive income	 	 	14,047	 	 	16,390	 	 	3,233	 	 	36,313	
 	 		 		 		 		
Comprehensive income	 	$	49,724	 	$	39,788	 	$	66,786	 	$	84,062	

Statement of Changes in Accumulated Other Comprehensive Income 
 	 	Net Deferred
Gain (Loss) on
Derivative
Instruments
	 	Currency
Translation
Adjustments
	 	Total
	 	
 	 	(unaudited)	 	
Balance at December 31, 2003	 	$	(7,692	)	$	39,861	 	$	32,169	 	
 	Current period activity:	 	 	 	 	 	 	 	 	 	 	
 	Reclassification adjustments for settled contracts	 	 	7,832	 	 	—	 	 	7,832	 	
 	Changes in fair value of outstanding hedge positions	 	 	4,418	 	 	—	 	 	4,418	 	
 	Currency translation adjustment	 	 	—	 	 	(9,017	)	 	(9,017	)	
 	 		 		 		 	
 	Total period activity	 	 	12,250	 	 	(9,017	)	 	3,233	 	
 	 		 		 		 	
Balance at June 30, 2004	 	$	4,558	 	$	30,844	 	$	35,402	 	
 	 		 		 		 	
The accompanying notes are an integral part of these consolidated financial statements. 
7

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") engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other petroleum products. We refer to liquefied petroleum gas and other petroleum products collectively as "LPG." Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. (formerly known as All American Pipeline, L.P.) and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana, Kansas and the Canadian provinces of Alberta and Saskatchewan. 
        The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of June 30, 2004, and December 31, 2003, (ii) the results of our consolidated operations for the three months and six months ended June 30, 2004 and 2003, (iii) our consolidated cash flows for the six months ended June 30, 2004 and 2003, (iv) our consolidated changes in partners' capital for the six months ended June 30, 2004, (v) our consolidated comprehensive income for the three months and six months ended June 30, 2004 and 2003, and (vi) our changes in consolidated accumulated other comprehensive income for the six months ended June 30, 2004. 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 and six months ended June 30, 2004 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 2003 Annual Report on Form 10-K/A Amendment No. 1. 
Change in Accounting Principle 
        During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third party assets. Historically, we have viewed pipeline linefill, whether in our assets or third party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Therefore, previously we have not included linefill barrels in the same average costing calculation as our operating inventory, but instead have carried linefill at historical cost. Following this change in accounting principle, the linefill in third party assets that we have historically classified as a portion of "Pipeline Linefill" on the face of the balance sheet (a long-term asset) and carried at historical cost, will be included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we will reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory" (a current asset), at average cost, and into "Inventory in Third Party Assets" (a long-term asset), which is now reflected as a separate line item within other assets on the consolidated balance sheet. 
        This change in accounting principle is effective January 1, 2004 and is reflected in the consolidated statement of operations for the six months ended June 30, 2004 and the consolidated balance sheet as of June 30, 2004, included herein. The cumulative effect of this change in accounting principle as of January 1, 2004, is a charge of approximately $3.1 million, representing a reduction in Inventory of approximately $1.7 million, a reduction in Pipeline Linefill of approximately $30.3 million and an 
8

increase in Inventory in Third Party Assets of $28.9 million. The pro forma impact for the second quarter of 2003 was not material to net income or net income per basic and diluted limited partner unit. The pro forma impact for the first half of 2003 would have been an increase to net income of approximately $1.8 million ($0.04 per basic and diluted limited partner unit) resulting in pro forma net income of $49.6 million and pro forma net income per limited partner unit (basic and diluted) of $0.91. 
        In conjunction with this change in accounting principle, we will classify cash flows associated with purchases and sales of linefill on assets that we own as cash flows from investing activities instead of the historical classification as cash flows from operating activities. Accordingly, the accompanying statement of cash flows for the six months ended June 30, 2003 has been revised to reclassify the cash paid for linefill in assets owned from operating activities to investing activities. The effect of the reclassification was an increase to net cash provided by operating activities and net cash used in investing activities of $28.5 million for the six months ended June 30, 2003. As a result of this change in classification, net cash provided by operating activities for the years ended December 31, 2003 and 2002 would increase to $115.3 million from $68.5 million and to $185.0 million from $173.9 million, respectively. Net cash used in investing activities for the years ended December 31, 2003 and 2002 would increase to $272.1 million from $225.3 million and $374.8 million from $363.8 million, respectively. In addition, net cash used in operating activities for the year ended December 31, 2001 would decrease from $30 million to $16.2 million and net cash used in investing activities would increase to $263.2 million from $249.5 million. 
Note 2—Acquisitions 
        The following acquisitions were made in 2004 and were accounted for under Statement of Financial Accounting Standards ("SFAS") No. 141 "Business Combinations." 
Link Energy LLC 
        On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link Energy LLC ("Link") for approximately $326 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) and approximately $58 million of net liabilities assumed and acquisition related costs. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions. The results of operations and assets from this acquisition (the "Link acquisition") have been included in our consolidated financial statements and both our pipeline operations and gathering, marketing, terminalling, and storage operations segments since April 1, 2004. 
9

        The purchase price was allocated as follows and includes goodwill primarily related to Link's gathering and marketing business (in millions): 
Fair value of assets acquired:	 	 	 	 	
Property and equipment	 	$	256.3	 	
Inventory	 	 	1.1	 	
Linefill	 	 	48.4	 	
Inventory in third party assets	 	 	15.1	 	
Goodwill	 	 	5.0	 	
Other long term assets	 	 	0.2	 	
 	 		 	
 	Subtotal	 	 	326.1	 	

Accounts receivable	

405.4	
 	
Other current assets	 	 	1.8	 	
 	 		 	
 	Subtotal	 	 	407.2	 	
 	
Total assets acquired	

733.3	

Fair value of liabilities assumed:	

 	
 	
Accounts payable and accrued liabilities	 	 	(448.9	)	
Other current liabilities	 	 	(8.5	)	
Other long-term liabilities	 	 	(7.4	)	
 	 		 	
 	Total liabilities assumed	 	 	(464.8	)	

Cash paid for acquisition	
 	
$	
268.5	
(1)	

(1)
Cash paid is net of $5.5 million subsequently returned to us from an indemnity escrow account and does not include the subsequent payment of various transaction and other acquisition related costs. 
        We are in the process of evaluating certain estimates made in the purchase price and related allocation; thus, the purchase price and allocation are both subject to refinement. In addition, we anticipate making capital expenditures of approximately $19.1 million to upgrade certain of the assets and comply with certain regulatory requirements. 
        The acquisition was initially funded with cash on hand, borrowings under a new $200 million, 364-day credit facility and borrowings under our existing revolving credit facilities (see Note 4). In connection with the acquisition, on April 15, 2004, we completed the private placement of 3,245,700 Class C common units to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors for $30.81 per unit, generating aggregate net proceeds of approximately $101 million, including the general partner's proportionate contribution. During the third quarter of 2004, we completed a public offering of common units, raising approximately $159 million net of expenses and inclusive of the underwriters' exercise of the overallotment option and the general partner's proportionate contribution. Proceeds from the public offering were used to retire a portion of the $200 million, 364-day credit facility. See Note 6. 
Capline and Capwood Pipeline Systems 
        In March 2004, we completed the acquisition of all of Shell Pipeline Company LP's interests in two entities for approximately $158.0 million in cash (including a $15.8 million deposit paid in December 2003) and approximately $0.5 million of transaction and other costs. In December 2003, subsequent to the announcement of the acquisition and in anticipation of closing, we issued approximately 2.8 million common units for net proceeds of approximately $88.4 million, after paying approximately $4.1 million of transaction costs. The proceeds from this issuance were used to pay down 
10

our revolving credit facility. At closing, the cash portion of this acquisition was funded from cash on hand and borrowings under our revolving credit facility. 
        The principal assets of these entities are: (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 667-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The results of operations and assets from this acquisition (the "Capline acquisition") have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2004. These pipelines provide one of the primary transportation routes for crude oil shipped into the Midwestern U.S., and delivered to several refineries and other pipelines. 
        The purchase price was allocated as follows (in millions): 
Crude oil pipelines and facilities	 	$	151.4	
Crude oil storage and terminal facilities	 	 	5.7	
Land	 	 	1.3	
Office equipment and other	 	 	0.1	
 	 		
Total	 	$	158.5	
 	 		
Pro Forma Data 
        The following unaudited pro forma data is presented to show pro forma revenues, income before cumulative effect of change in accounting principle, net income, basic and diluted income before cumulative effect of accounting change per limited partner unit and basic and diluted net income per limited partner unit for the Partnership as if the Capline and Link acquisitions had occurred as of the beginning of the periods reported (in millions, except per unit amounts): 
 	 	Six Months Ended
June 30,
	
 	 	2004
	 	2003
	
Revenues	 	$	8,984.3	 	$	6,106.8	
 	 		 		
Income before cumulative effect of change in accounting principle(1)	 	$	49.5	 	$	108.9	
 	 		 		
Net income(2)	 	$	46.4	 	$	104.9	
 	 		 		
Basic and diluted income before cumulative effect of change in accounting principle per limited partner unit(1)	 	$	0.76	 	$	2.04	
 	 		 		
Basic and diluted net income per limited partner unit(2)	 	$	0.70	 	$	1.97	

(1)
Includes a net gain in the 2003 period of approximately $67.5 million related to Link's predecessor company's reorganization, discharge of debt and fresh start adjustments. 
(2)
The 2003 period includes the amounts described in note (1) above for Link's predecessor company's reorganization, discharge of debt and fresh start adjustments along with a loss of approximately $4.0 million related to Link's predecessor company's cumulative effect of change in accounting principle. 

Other Acquisitions 
        On May 7, 2004, we completed the acquisition of the Cal Ven Pipeline System from Cal Ven Limited, a subsidiary of Unocal Canada Limited. The total purchase price was approximately 
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$19 million, including transaction costs. The transaction was funded through a combination of cash on hand and borrowings under our revolving credit facilities. The Cal Ven Pipeline System includes approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The system is located in northern Alberta and delivers crude oil into the Rainbow Pipeline System. The Rainbow Pipeline System then transports the crude south to the Edmonton market, where it can be used in local refineries or shipped on connecting pipelines to the U.S. market. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our pipeline operations segment since May 1, 2004. 
Note 3—Trade Accounts Receivable 
        The majority of our trade accounts receivable relate to our gathering and marketing activities and can generally be described as high volume and low margin activities. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered, received 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. Based on these analyses, as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable. At June 30, 2004, approximately 99% of our net trade accounts receivable were less than 60 days past the scheduled invoice date. Our allowance for doubtful trade accounts receivable totaled $0.4 million. We consider this reserve adequate; however, there is no assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations. 
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Note 4—Debt 
        Debt consists of the following (in millions): 
 	 	June 30,
2004
	 	December 31,
2003
	
Short-term debt:	 	 	 	 	 	 	

Senior secured hedged inventory borrowing facility bearing interest at a rate of 2.0% and 1.9% at June 30, 2004 and December 31, 2003, respectively	
 	
$	
4.4	
 	
$	
100.5	
Working capital borrowings on senior unsecured $425 million domestic revolving credit facility, bearing interest at a rate of 4.0% at both June 30, 2004 and December 31, 2003, respectively(1) 	 	 	13.2	 	 	25.3	
Other	 	 	4.4	 	 	1.5	
 	 		 		
 	Total short-term debt	 	 	22.0	 	 	127.3	

Long-term debt:	

 	

 	

$200 million revolving credit facility, bearing interest at a rate of 2.3% at June 30, 2004	
 	
$	
200.0	
 	
$	
—	
Senior unsecured $425 million domestic revolving credit facility, bearing interest at 2.3% at June 30, 2004(1)	 	 	90.0	 	 	—	
Senior unsecured $30 million Canadian working capital revolving credit facilty, bearing interest at a rate of 4.4% at June 30, 2004	 	 	25.7	 	 	—	
Senior unsecured $170 million Canadian revolving credit facility, bearing interest at a rate of 2.3% and 2.2% at June 30, 2004 and December 31, 2003, respectively	 	 	170.0	 	 	70.0	
7.75% senior notes due October 2012, net of unamortized discount of $0.3 million and $0.3 million at June 30, 2004 and December 31, 2003, respectively	 	 	199.7	 	 	199.7	
5.63% senior notes due December 2013, net of unamortized discount of $0.6 million and $0.7 million at June 30, 2004 and December 31, 2003, respectively	 	 	249.4	 	 	249.3	
 	 		 		
 	Total long-term debt(1)	 	 	934.8	 	 	519.0	
 	 		 		
Total debt	 	$	956.8	 	$	646.3	

(1)
At June 30, 2004 and December 31, 2003, we have classified $13.2 million and $25.3 million, respectively, of borrowings under our senior unsecured $425 million domestic revolving credit facility as short-term. These borrowings are designated as working capital borrowings and primarily are for hedged LPG inventory and New York Mercantile Exchange margin deposits and must be repaid within one year. 
        In connection with the Link acquisition, we entered into a new $200 million revolving credit facility that has a 364-day term and contains a twelve-month term out option, exercisable at our election, at the end of the primary term. We have classified amounts outstanding under this facility as long-term as we have both the intent and the ability to refinance these amounts into long-term borrowings. The facility bears interest at a rate of LIBOR plus a margin ranging from .625% to 1.25%, depending upon our credit rating, and includes essentially the same covenants as our existing credit facilities. We repaid approximately $160 million of amounts outstanding under this facility with proceeds from our third quarter 2004 equity offering, and have committed to use net proceeds from future debt and equity offerings to prepay indebtedness outstanding and reduce the commitment level. See Note 6. 
        On August 5, 2004, we sold $175 million of 4.75% Senior Notes due 2009 and $175 million of 5.88% Senior Notes due 2016. The 4.75% notes were sold at 99.551% and the 5.88% notes were sold at 99.345% of face value. We expect to close the sale on August 12, 2004, with proceeds after initial purchaser discount and offering costs of approximately $345.3 million. We intend to use the proceeds to 
13

repay amounts outstanding under our credit facilities, including the remaining balance under the $200 million, 364-day facility we used to fund the Link acquisition, and for general partnership purposes. 
        We are in the process of increasing the capacity of our uncommitted senior secured hedged inventory facility from $200 million to $300 million, primarily as a result of increased crude oil prices and an increase in our crude oil storage capacity as a result of acquisitions. We expect to complete the increase during the third quarter. 
Note 5—Earnings Per Common Unit 
        The following table sets forth the computation of basic and diluted earnings per limited partner unit: 
 	 	Three months ended June 30,
	 	Six months ended June 30,
	 	
 	 	2004
	 	2003
	 	2004
	 	2003
	 	
 	 	(in thousands, except per unit data)	 	
Net income	 	$	35,677	 	$	23,398	 	$	63,553	 	$	47,749	 	
Less:	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	General partner incentive distributions	 	 	(1,752	)	 	(1,266	)	 	(3,396	)	 	(2,274	)	
 	General partner 2% ownership	 	 	(678	)	 	(442	)	 	(1,203	)	 	(909	)	
 	 		 		 		 		 	
Numerator: net income available for common unitholders	 	$	33,247	 	$	21,690	 	$	58,954	 	$	44,566	 	
 	 		 		 		 		 	
Denominator: weighted average number of limited partner units outstanding	 	 	61,556	 	 	52,223	 	 	59,985	 	 	51,200	 	
 	 		 		 		 		 	
Basic and diluted net income per limited partner unit	 	$	0.54	 	$	0.42	 	$	0.98	 	$	0.87	 	
 	 		 		 		 		 	
        In March 2004, the Emerging Issues Task Force issued Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128." EITF 03-06 addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. The adoption of EITF 03-06 did not result in a change in the Partnership's earnings per limited partner unit for any of the periods presented. 
Note 6—Partners' Capital and Distributions 
Subordinated Unit Conversion 
        In November 2003, pursuant to the terms of our Partnership Agreement, 25% of our subordinated units converted to common units on a one-for-one basis. In February 2004, all of the remaining subordinated units converted to common units on a one-for-one basis. 
Issuance of Common Units 
        Long-Term Incentive Plan.    We issued approximately 138,000 common units during the first quarter of 2004 and approximately 177,500 common units during the second quarter of 2004 in conjunction with the vesting of awards under our Long-Term Incentive Plan ("LTIP"). In connection with such 
14

issuances, the General Partner made a proportional two percent contribution. See Note 7 for additional discussion. 
        Payment of Deferred Acquisition Price.    In connection with the CANPET acquisition in July 2001, $26.5 million Canadian of the purchase price, payable in common units or cash at our option, was deferred subject to various performance objectives being met. These objectives were met as of December 31, 2003 and an increase to goodwill for this liability was recorded as of that date. The liability was satisfied on April 30, 2004 with the issuance of approximately 385,000 common units and the payment of $6.5 million in cash. The number of common units issued in satisfaction of the deferred payment was based upon $34.02 per share, the average trading price of our common units for the ten-day trading period prior to the payment date, and a Canadian dollar to U.S. dollar exchange rate of 1.35 to 1, the average noon-day exchange rate for the ten-day trading period prior to the payment date. In addition, an incremental $3.7 million in cash was paid for the distributions that would have been paid on the common units had they been outstanding since the effective date of the acquisition. 
        Private Placement of Class C Common Units.    In connection with the Link acquisition, on April 15, 2004 we issued 3,245,700 Class C common units for $30.81 per unit in a private placement to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million, and were used to reduce the balance outstanding under our revolving credit facilities. The Class C common units are unlisted securities that are pari passu in voting and distribution rights with the Partnership's publicly traded common units. The Class C common units are similar in many respects to the Partnership's Class B common units. The Class C common units are convertible into common units upon approval by the holders of a majority of the common units. Beginning six months from the closing of the private placement, the Class C unitholders may request that the Partnership call a meeting of its common unitholders to consider approval of the conversion of the Class C units into common units. If the approval of the conversion is not obtained within 120 days of the request, the Class C unitholders will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit. If the approval of the conversion is not secured within 90 days after the end of the 120-day period, the distribution right increases to 115%. The holder of our Class B common units, Plains Holdings Inc., has a similar right to request a unitholder meeting, which is currently exercisable. 
        Equity Offering.    In the third quarter of 2004, we completed a public offering of 4,904,000 common units for $33.25 per unit. The offering resulted in gross proceeds of approximately $163.1 million from the sale of units and approximately $3.3 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $7.3 million. Net proceeds of $159.1 million were used to permanently reduce outstanding borrowings under the $200 million, 364-day credit facility (see Note 4). 
Distributions 
        On July 21, 2004, we declared a cash distribution of $0.5775 per unit on our outstanding common units, Class B common units and Class C common units. The distribution is payable on August 13, 2004, to unitholders of record on August 3, 2004, for the period April 1, 2004, through June 30, 2004. The total distribution to be paid is approximately $41.8 million, with approximately $38.8 million to be paid to our common unitholders and $0.8 million and $2.2 million to be paid to our general partner for its general partner and incentive distribution interests, respectively. 
        On April 23, 2004, we declared a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and Class C common units. The distribution was paid on May 14, 2004, to unitholders of record on May 4, 2004, for the period January 1, 2004, through March 31, 2004. The 
15

total distribution paid was approximately $37.5 million, with approximately $35.0 million paid to our common unitholders and $0.7 million and $1.8 million paid to our general partner for its general partner and incentive distribution interests, respectively. 
        On January 22, 2004, we declared a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid on February 13, 2004, to unitholders of record on February 3, 2004, for the period October 1, 2003, through December 31, 2003. The total distribution paid was approximately $35.2 million, with approximately $28.7 million paid to our common unitholders, $4.2 million paid to our subordinated unitholders and $0.7 million and $1.6 million paid to our general partner for its general partner and incentive distribution interests, respectively. 
Note 7—Vesting of Unit Grants Under Long-Term Incentive Plan 
        During the first half of 2004, approximately 796,000 phantom units vested. We paid cash in lieu of delivery of common units for approximately 306,000 of the phantom units and issued approximately 315,500 new common units (after netting for taxes) in connection with the remainder of the vesting. 
        Under generally accepted accounting principles, we are required to recognize an expense when it is considered probable that phantom unit grants under our LTIP will vest. During the first half of 2004, we recognized $4.2 million of compensation expense related to the vesting of phantom units under the LTIP. This expense includes an anticipated vesting in August 2004. We will recognize additional expense when it is considered probable that additional vestings will occur. Generally, future vestings will occur when the annualized distribution rate reaches $2.50 and again at $2.70. We anticipate that, after giving effect to the August vesting and related tax withholding and cash settlement, approximately 874,000 phantom units will be available under the plan for future grant and approximately 140,000 phantom units will remain outstanding. In accordance with the provisions of the LTIP and applicable NYSE standards, no more than approximately 564,000 of such phantom unit grants (outstanding or future) could be satisfied by delivery of common units. 
Note 8—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. 
Summary of Financial Impact 
        The following is a summary of the financial impact of the derivative instruments and hedging activities discussed below. The June 30, 2004, balance sheet includes assets of $35.4 million ($27.7 million current), liabilities of $23.5 million ($16.3 million current) and unrealized net gains deferred to Other Comprehensive Income ("OCI") of $4.6 million. Earnings for the six months ended June 30, 2004, include a gain of $10.7 million (including a gain of $7.1 million that was reclassified into earnings from OCI during the period). 
        As of June 30, 2004, 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 six months ended June 30, 2004, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Of the $4.6 million net gain deferred in OCI at June 30, 2004, a net gain of $11.0 million will be reclassified into earnings in the next twelve months and the remaining net loss at various intervals ending in 2013. Since a portion of 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. 
16

        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 NYMEX 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 the instruments that qualify for hedge accounting are 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. 
Controlled Trading Program 
        Although we seek to maintain a position that is substantially balanced within our crude oil lease purchase activities, we may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions. 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 an aggregate of 500,000 barrels of crude oil. 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 in fair value recorded net in revenues. 
Interest Rate Risk Hedging 
        At June 30, 2004, we have no open interest rate hedging instruments. However, there is approximately $5.4 million deferred in OCI that relates to instruments terminated and cash settled in 2003. The net deferred loss related to these instruments is being amortized into interest expense over the original terms of the terminated instruments (approximately fifty percent over three years and the remaining fifty percent over ten years). Approximately $0.7 million related to the terminated instruments has been reclassified into interest expense during the first half of 2004, and approximately $1.4 million will be reclassified for the entire year of 2004. In addition, earnings for the first half of 2004 include a loss of approximately $0.7 million that was reclassified out of OCI related to an instrument that matured in March 2004. 
Currency Exchange Rate Risk Hedging 
        Because a significant portion of our Canadian business is conducted in Canadian dollars, we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include forward exchange contracts and cross currency swaps. The forward exchange contracts qualify for hedge accounting as cash flow hedges and the cross currency swaps qualify for hedge accounting as fair value hedges, both in accordance with SFAS 133. Additionally, at times, a portion of our debt is denominated in Canadian dollars. At June 30, 2004, $4.0 million of our long-term debt was denominated in Canadian dollars ($5.3 million Canadian based on a Canadian dollar to U.S. dollar exchange rate of 1.33 to 1). All of these financial instruments are placed with what we believe to be large creditworthy financial institutions. 
17

        At June 30, 2004, we had forward exchange contracts that allow us to exchange $2.0 million Canadian for approximately $1.5 million U.S. quarterly during 2004 and approximately $1.0 million Canadian for approximately $0.7 million U.S. quarterly during 2005 (based on a Canadian dollar to U.S. dollar exchange rate of 1.33 to 1 and 1.34 to 1, respectively). In addition, at June 30, 2004, we also had cross currency swap contracts for an aggregate notional principal amount of $21.0 million, effectively converting this amount of our U.S. dollar denominated debt to $32.5 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1). The notional principal amount reduces by $2.0 million U.S. in May 2005 and has a final maturity in May 2006 of $19.0 million U.S. 
Note 9—Commitments and Contingencies 
Litigation 
        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 ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Department of Commerce. In 2002, we determined that we may 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. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, we received a request from the BIS for additional information. 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 this matter. 
        General.    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. 
Environmental 
        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. At June 30, 2004, our reserve for environmental liabilities totaled approximately $23.5 million. Approximately $15.7 million of the reserve is related to liabilities assumed as part of the Link acquisition. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows. 
Other 
        The occurrence of a significant event not fully insured, indemnified or reserved against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. We believe that our levels of coverage and 
18

retention are generally consistent with those of similarly situated companies in our industry. 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, or that we have established adequate reserves to the extent that such risks are not insured. 
Note 10—Operating Segments 
        Our operations consist of two operating segments: (1) Pipeline Operations—engages in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; and (2) Gathering, Marketing, Terminalling and Storage Operations—engages 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 believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flow. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow. 
        We evaluate segment performance based on segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs, and (iii) segment general and administrative expenses. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to 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. The following table reflects our results of operations for each segment 
19

for the periods indicated (note that each of the items in the following table excludes depreciation and amortization): 
 	 	Pipeline
	 	Gathering,
Marketing,
Terminalling
& Storage
	 	Total
	 	
 	 	(in millions)	 	
Three Months Ended June 30, 2004	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	
 	External Customers	 	$	190.7	 	$	4,941.1	 	$	5,131.8	 	
 	Intersegment(1)	 	 	32.1	 	 	0.2	 	 	32.3	 	
 	 		 		 		 	
 	 	Total revenues of reportable segments	 	$	222.8	 	$	4,941.3	 	$	5,164.1	 	
 	 		 		 		 	
Segment profit	 	$	47.7	 	$	13.5	 	$	61.2	 	
 	 		 		 		 	
Non-cash SFAS 133 impact(2)	 	$	—	 	$	(6.9	)	$	(6.9	)	
 	 		 		 		 	
Maintenance capital	 	$	0.6	 	$	0.7	 	$	1.3	 	

Three Months Ended June 30, 2003	

 	

 	

 	
 	
Revenues:	 	 	 	 	 	 	 	 	 	 	
 	External Customers	 	$	143.3	 	$	2,565.9	 	$	2,709.2	 	
 	Intersegment(1)	 	 	12.5	 	 	0.3	 	 	12.8	 	
 	 		 		 		 	
 	 	Total revenues of reportable segments	 	$	155.8	 	$	2,566.2	 	$	2,722.0	 	
 	 		 		 		 	
Segment profit	 	$	24.2	 	$	18.9	 	$	43.1	 	
 	 		 		 		 	
Non-cash SFAS 133 impact(2)	 	$	—	 	$	0.2	 	$	0.2	 	
 	 		 		 		 	
Maintenance capital	 	$	2.4	 	$	0.2	 	$	2.6	 	
 	 		 		 		 	
20

 	 	Pipeline
	 	Gathering,
Marketing,
Terminalling
& Storage
	 	Total
	
 	 	(in millions)	
Six Months Ended June 30, 2004	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	
 	External Customers	 	$	364.2	 	$	8,572.2	 	$	8,936.4	
 	Intersegment(1)	 	 	47.9	 	 	0.4	 	 	48.3	
 	 		 		 		
 	 	Total revenues of reportable segments	 	$	412.1	 	$	8,572.6	 	$	8,984.7	
 	 		 		 		
Segment profit	 	$	73.2	 	$	41.6	 	$	114.8	
 	 		 		 		
Non-cash SFAS 133 impact(2)	 	$	—	 	$	0.5	 	$	0.5	
 	 		 		 		
Maintenance capital	 	$	2.1	 	$	1.0	 	$	3.1	

Six Months Ended June 30, 2003	

 	

 	

 	
Revenues:	 	 	 	 	 	 	 	 	 	
 	External Customers	 	$	302.3	 	$	5,688.8	 	$	5,991.1	
 	Intersegment(1)	 	 	22.5	 	 	0.5	 	 	23.0	
 	 		 		 		
 	 	Total revenues of reportable segments	 	$	324.8	 	$	5,689.3	 	$	6,014.1	
 	 		 		 		
Segment profit	 	$	44.4	 	$	43.3	 	$	87.7	
 	 		 		 		
Non-cash SFAS 133 impact(2)	 	$	—	 	$	1.1	 	$	1.1	
 	 		 		 		
Maintenance capital	 	$	3.8	 	$	0.4	 	$	4.2	

(1)
Intersegment sales are conducted at arms length. 
(2)
Amounts related to SFAS 133 are included in revenues and impact segment profit. 
        The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle (in millions): 
 	 	For the three months
ended June 30,
	 	For the six months
ended June 30,
	 	
 	 	2004
	 	2003
	 	2004
	 	2003
	 	
Segment profit	 	$	61.2	 	$	43.1	 	$	114.8	 	$	87.7	 	
Depreciation and amortization	 	 	(16.0	)	 	(11.3	)	 	(29.1	)	 	(22.2	)	
Interest expense	 	 	(10.0	)	 	(8.5	)	 	(19.5	)	 	(17.7	)	
Interest income and other, net	 	 	0.5	 	 	0.1	 	 	0.5	 	 	(0.1	)	
 	 		 		 		 		 	
Income before cumulative effect of change in accounting principle	 	$	35.7	 	$	23.4	 	$	66.7	 	$	47.7	 	
 	 		 		 		 		 	
21

Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 
Introduction 
        The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes. For more detailed information regarding the basis of presentation for the following financial information, see the "Notes to the Consolidated Financial Statements." Our discussion and analysis includes the following: 
•
Executive Summary 
•
Acquisition Activities 
•
Results of Operations 
•
Outlook 
•
Liquidity and Capital Resources 
Executive Summary 
        Company Overview—Plains All American Pipeline, L.P. is a Delaware limited partnership (the "Partnership") formed in September of 1998. Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. (formerly known as All American Pipeline, L.P.) and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other petroleum products. We refer to liquefied petroleum gas and other petroleum products collectively as "LPG." We own an extensive network in the United States and Canada of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs. 
        We are one of the largest midstream crude oil companies in North America, with over 14,000 miles of crude oil pipelines, approximately 37.0 million barrels of terminalling and storage capacity and a full complement of truck transportation and injection assets. On average, we handle over 2.6 million barrels per day of physical crude oil through our extensive network of assets located in major oil producing regions of the United States and Canada. Our operations are conducted primarily in Texas, Oklahoma, California, Louisiana, Kansas and the Canadian provinces of Alberta and Saskatchewan and consist of two operating segments: (i) pipeline operations and (ii) gathering, marketing, terminalling and storage operations ("GMT&S"). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets. 
        Second Quarter 2004 Operating Results Overview—During the second quarter of 2004, we recognized net income and earnings per limited partner unit of $35.7 million and $0.54, respectively, which was a 52% and 29% increase, respectively, over the second quarter of 2003. The results for the second quarter of 2004 compared to the second quarter of 2003 include significant contributions from the acquisitions completed during the second half of 2003 and the first half of 2004. In addition, the 2004 results include a non-cash loss of approximately $6.9 million resulting from the mark-to-market of open derivative instruments pursuant to Statement of Financial Accounting Standard No. 133, as amended (SFAS 133), while the second quarter of 2003 includes a non-cash gain of approximately $0.2 million. 
22

        Significant events in the quarter that affected our results of operations were as follows: 
•
We acquired all of the North American crude oil and pipeline operations of Link Energy LLC ("Link") for approximately $326 million. The acquisition was initially funded with cash on hand, borrowings under a new $200 million, 364-day credit facility and borrowings under our existing revolving credit facilities. In connection with this acquisition, on April 15, 2004, we completed the private placement of 3,245,700 Class C common units to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors for $30.81 per unit, generating aggregate proceeds of approximately $101 million, including the general partner's proportionate contribution. See "—Acquisitions Activities" and "Liquidity and Capital Resources—Liquidity." 
•
We changed our method of accounting for pipeline linefill in third party assets resulting in a cumulative effect of change in accounting principle of $3.1 million. Historically, we have viewed pipeline linefill, whether in our assets or third party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Following this change in accounting principle, the linefill in third party assets that we have historically classified as a portion of "Pipeline Linefill" on the face of the balance sheet (a long-term asset) and carried at historical cost, will be included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we will reclassify linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory" (a current asset) and into "Inventory in Third Party Assets" (a long-term asset) at average cost, which is now reflected as a separate line item within other assets on the consolidated balance sheet. 
        Prospects for the Future—We believe we are well situated to optimize our position in and around our existing assets and to expand our asset base by continuing to consolidate, rationalize and optimize the North American crude oil infrastructure. We have deliberately configured our assets to provide a counter-cyclical balance between our gathering and marketing activities and our terminalling and storage activities. We believe the combination of these balanced activities with our relatively stable, fee-based pipeline assets enables us to generate stable financial results in an industry that is highly cyclical. 
        During the second quarter of 2004 we further strengthened our position by expanding our asset base through acquisition and internal growth projects. We will continue to pursue the purchase of midstream crude oil assets, and we will also continue to initiate projects designed to optimize crude oil flows in the areas in which we operate. Although we believe that we are well situated in the North American crude oil infrastructure, we face various operational, regulatory and financial challenges that may impact our ability to execute our strategy as planned. See "—Forward Looking Statements and Associated Risks" for further discussion of these items. 
Acquisition Activities 
        We completed several acquisitions during 2004 and 2003 that have impacted the results of operations and liquidity discussed herein. The following acquisitions were accounted for, and the purchase prices were allocated, in accordance with SFAS 141 "Business Combinations." Our ongoing acquisition activity is discussed further in "Outlook" below. 
        In the first half of 2004, we completed several acquisitions for aggregate consideration of approximately $506.1 million. The aggregate consideration includes cash paid, estimated transaction 
23

costs and assumed liabilities and net working capital items. The following table summarizes our 2004 acquisitions (in millions), and a description of each of the 2004 transactions follows the table: 
Acquisition
	 	Effective
Date
	 	Acquisition
Price
	 	Operating Segment
	
Capline and Capwood Pipeline Systems	 	03/01/04	 	$	158.5	 	Pipeline	
Link Energy LLC	 	04/01/04	 	 	326.1	 	Pipeline/GMT&S	
Cal Ven Pipeline System	 	05/01/04	 	 	19.0	 	Pipeline	
Other(1)	 	06/01/04	 	 	2.5	 	Pipeline	
 	 	 	 		 	 	
Total 2004 Acquisitions through June 30, 2004	 	 	 	$	506.1	 	 	

(1)
Includes several acquisitions that had an immaterial impact on results of operations for the period. 
Capline and Capwood Pipeline Systems 
        In March 2004, we completed the acquisition of all of Shell Pipeline Company LP's interests in two entities for approximately $158.0 million in cash (including a $15.8 million deposit paid in December 2003) and approximately $0.5 million of transaction and other costs. The principal assets of the entities are: (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 667-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The results of operations and assets from this acquisition (the "Capline acquisition") have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2004. These pipelines provide one of the primary transportation routes for crude oil shipped into the Midwestern U.S. and delivered to several refineries and other pipelines. 
        The purchase price was allocated as follows (in millions): 
Crude oil pipelines and facilities	 	$	151.4	
Crude oil storage and terminal facilities	 	 	5.7	
Land	 	 	1.3	
Office equipment and other	 	 	0.1	
 	 		
Total	 	$	158.5	
 	 		
Link Energy LLC 
        On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link Energy LLC ("Link") for approximately $326 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to PAA from an indemnity escrow account) and approximately $58 million of net liabilities assumed and acquisition related costs. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions. The results of operations and assets from this acquisition (the "Link acquisition") have been included in our consolidated financial statements and both our pipeline operations and GMT&S operations segments since April 1, 2004. 
24

        The purchase price was allocated as follows and includes goodwill primarily related to Link's gathering and marketing business (in millions): 
Fair value of assets acquired:	 	 	 	 	
Property and equipment	 	$	256.3	 	
Inventory	 	 	1.1	 	
Linefill	 	 	48.4	 	
Inventory in third party assets	 	 	15.1	 	
Goodwill	 	 	5.0	 	
Other long term assets	 	 	0.2	 	
 	 		 	
 	Subtotal	 	 	326.1	 	

Accounts receivable	

405.4	
 	
Other current assets	 	 	1.8	 	
 	 		 	
 	Subtotal	 	 	407.2	 	
 	
Total assets acquired	

733.3	

Fair value of liabilities assumed:	

 	
 	
Accounts payable and accrued liabilities	 	 	(448.9	)	
Other current liabilities	 	 	(8.5	)	
Other long-term liabilities	 	 	(7.4	)	
 	 		 	
 	Total liabilities assumed	 	 	(464.8	)	

Cash paid for acquisition	
 	
$	
268.5	
(1)	

(1)
Cash paid is net of $5.5 million subsequently returned to us from an indemnity escrow account and does not include the subsequent payment of various transaction and other acquisition related costs. 
        We are in the process of evaluating certain estimates made in the purchase price and related allocation; thus, the purchase price and allocation are both subject to refinement. In addition, we anticipate making capital expenditures of approximately $19.1 million to upgrade certain of the assets and comply with certain regulatory requirements. 
        On April 2, 2004, the Office of the Attorney General of Texas (the "Texas AG") delivered written notice to us that it was investigating the possibility that the acquisition of Link's assets might reduce competition in one or more markets within the petroleum products industry in the State of Texas. In connection with the Link purchase, both PAA and Link completed all necessary filings required under the Hart-Scott-Rodino Act, and the required 30-day waiting period expired on March 24, 2004 without any inquiry or request for additional information from the U.S. Department of Justice or the Federal Trade Commission. Representatives from the Antitrust and Civil Medicaid Fraud Division of the Office of the Attorney General of Texas indicated their investigation was prompted by complaints received from allegedly interested industry parties regarding the potential impact on competition in the Permian Basin area of West Texas. We understand that similar complaints have been received by the Federal Trade Commission, and that, consistent with federal-state protocols for conducting joint merger investigations, appropriate federal and state antitrust authorities are coordinating their activities. In June 2004 we received from the Texas AG a request for additional information. We have complied with that request and are cooperating fully with the antitrust enforcement authorities. 
Cal Ven Pipeline System 
        On May 7, 2004 we completed the acquisition of the Cal Ven Pipeline System from Cal Ven Limited, a subsidiary of Unocal Canada Limited. The total purchase price was approximately $19 million, including transaction costs. The transaction was funded through a combination of cash on hand and borrowings under our revolving credit facilities. The Cal Ven Pipeline System includes approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The system is 
25

located in northern Alberta and delivers crude oil into the Rainbow Pipeline System. The Rainbow Pipeline System then transports the crude south to the Edmonton market, where it can be used in local refineries or shipped on connecting pipelines to the U.S. market. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our pipeline operations segment since May 1, 2004. 
2003 Acquisitions 
        During 2003, we completed ten acquisitions for aggregate consideration of approximately $159.5 million. The aggregate consideration includes cash paid, estimated transaction costs, assumed liabilities and estimated near-term capital costs. The acquisitions were initially financed with borrowings under our credit facilities, which were subsequently repaid with a portion of the proceeds from our equity issuances and the issuance of senior notes. The businesses acquired during 2003 impacted our results of operations subsequent to the effective date of each acquisition as indicated below. These acquisitions included mainline crude oil pipelines, crude oil gathering lines, terminal and storage facilities, and an underground LPG storage facility. With the exception of $0.5 million that was allocated to goodwill and other intangible assets and $4.7 million associated with crude oil linefill and working inventory, the remaining aggregate purchase price was allocated to property and equipment. The following table details our 2003 acquisitions (in millions): 
Acquisition
	 	Effective
Date
	 	Acquisition
Price
	 	Operating Segment
	
Red River Pipeline System	 	02/01/03	 	$	19.4	 	Pipeline	
Iatan Gathering System	 	03/01/03	 	 	24.3	 	Pipeline	
Mesa Pipeline System(1)	 	05/05/03	 	 	2.9	 	Pipeline	
South Louisiana Assets(2)	 	06/01/03	 	 	13.4	 	Pipeline/GMT&S	
Alto Storage Facility	 	06/01/03	 	 	8.5	 	GMT&S	
Iraan to Midland Pipeline System	 	06/30/03	 	 	17.6	 	Pipeline	
ArkLaTex Pipeline System	 	10/01/03	 	 	21.3	 	Pipeline/GMT&S	
South Saskatchewan Pipeline System	 	11/01/03	 	 	47.7	 	Pipeline	
Atchafalaya Pipeline System(3)	 	12/01/03	 	 	4.4	 	Pipeline	
 	 	 	 		 	 	
Total 2003 Acquisitions	 	 	 	$	159.5	 	 	

(1)
Consists of an 8.8% undivided interest. 
(2)
Includes a 33.3% interest in Atchafalaya Pipeline L.L.C. 
(3)
Includes two acquisitions each for 33.3% interests in Atchafalaya Pipeline L.L.C. that, when combined with the acquisition referenced in (2) above, results in a total ownership of 100%. 
Results of Operations 
Analysis of 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 GMT&S 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 segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs and (iii) segment general and administrative ("G&A") expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our "Available Cash" (as defined in our Partnership Agreement) to our unitholders. Therefore, we look at each period's earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of 
26

segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which we believe significantly mitigate the decline in the actual value of our principal fixed assets. These maintenance costs are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to 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. See Note 10 "Operating Segments" in the "Notes to the Consolidated Financial Statements" for a reconciliation of segment profit to consolidated income before cumulative effect of accounting change. 
Three Months Ended June 30, 2004 and 2003 
        For the three months ended June 30, 2004, we reported consolidated net income of $35.7 million on total revenues of $5.1 billion compared to net income for the same period in 2003 of $23.4 million on total revenues of $2.7 billion. The following table reflects our results of operations and maintenance capital for each segment (note that each of the items in the following table excludes depreciation and amortization). 
 	 	Pipeline
	 	GMT&S
	 	
 	 	(in millions)	 	
Three Months Ended June 30, 2004(1)	 	 	 	 	 	 	 	
Revenues	 	$	222.8	 	$	4,941.3	 	
Purchases	 	 	(132.9	)	 	(4,891.3	)	
Field operating costs	 	 	(31.9	)	 	(27.2	)	
Segment G&A expenses(2)	 	 	(10.3	)	 	(9.3	)	
 	 		 		 	
Segment profit	 	$	47.7	 	$	13.5	 	
 	 		 		 	
Noncash SFAS 133 impact(3)	 	$	—	 	$	(6.9	)	
 	 		 		 	
Maintenance capital	 	$	0.6	 	$	0.7	 	

Three Months Ended June 30, 2003(1)	

 	

 	
 	
Revenues	 	$	155.8	 	$	2,566.2	 	
Purchases	 	 	(112.9	)	 	(2,521.2	)	
Field operating costs	 	 	(14.2	)	 	(18.4	)	
Segment G&A expenses(2)	 	 	(4.5	)	 	(7.7	)	
 	 		 		 	
Segment profit	 	$	24.2	 	$	18.9	 	
 	 		 		 	
Noncash SFAS 133 impact(3)	 	$	—	 	$	0.2	 	
 	 		 		 	
Maintenance capital	 	$	2.4	 	$	0.2	 	

(1)
Revenues and purchases include intersegment amounts. 
(2)
Segment 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. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period. 
(3)
Amounts related to SFAS 133 are included in revenues and impact segment profit. 
27

Pipeline Operations 
        As of June 30, 2004, we owned and operated over 14,000 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 and third-party leases of pipeline capacity (collectively referred to as "tariff activities"), as well as barrel exchanges and buy/sell arrangements (collectively referred to as "pipeline margin activities"). In connection with certain of our merchant activities conducted under our gathering and marketing business, we are also shippers on certain of our own pipelines. These transactions are conducted at published tariff rates and eliminated in consolidation. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit 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 field costs of operating the pipeline. Segment profit from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount. 
        The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated: 
 	 	Three months ended June 30,
	 	
 	 	2004
	 	2003
	 	
Operating Results(1) (in millions)	 	 	 	 	 	 	 	
 	Revenues	 	 	 	 	 	 	 	
 	 	Tariff activities	 	$	84.0	 	$	38.3	 	
 	 	Pipeline margin activities	 	 	138.8	 	 	117.5	 	
 	 		 		 	
 	Total pipeline operations revenues	 	 	222.8	 	 	155.8	 	
 	
Costs and Expenses	

 	

 	
 	
 	 	Pipeline margin activities purchases	 	 	(132.9	)	 	(112.9	)	
 	 	Field operating costs	 	 	(31.9	)	 	(14.2	)	
 	Segment G&A expenses(2)	 	 	(10.3	)	 	(4.5	)	
 	 		 		 	
 	Segment profit	 	$	47.7	 	$	24.2	 	
 	 		 		 	
 	Maintenance capital	 	$	0.6	 	$	2.4	 	

Average Daily Volumes (thousands of barrels per day)(3)	

 	

 	
 	
 	Tariff activities	 	 	 	 	 	 	 	
 	 	All American	 	 	59	 	 	63	 	
 	 	Basin	 	 	271	 	 	280	 	
 	 	Link acquisition	 	 	369	 	 	—	 	
 	 	Capline	 	 	169	 	 	—	 	
 	 	Other domestic	 	 	468	 	 	253	 	
 	 	Canada	 	 	259	 	 	169	 	
 	 		 		 	
 	Total tariff activities	 	 	1,595	 	 	765	 	
 	Pipeline margin activities	 	 	74	 	 	75	 	
 	 		 		 	
 	 	 	Total	 	 	1,669	 	 	840	 	

(1)
Revenues and purchases include intersegment amounts. 
(2)
Segment 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. 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 total volumes transported for the number of days we actually owned the assets divided by the number of days in the period. 
28

        Total average daily volumes transported were approximately 1.7 million barrels per day and 0.8 million barrels per day for the three months ended June 30, 2004 and 2003, respectively. The increase relates to our tariff activities. As discussed above, we have completed a number of acquisitions during 2004 and 2003 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
June 30,
	
 	 	2004
	 	2003
	
 	 	(thousands of barrels per day)	
Tariff activities(1)	 	 	 	 	
 	2004 acquisitions	 	702	 	—	
 	2003 acquisitions	 	171	 	52	
 	All other pipeline systems	 	722	 	713	
 	 		 		
 	Total tariff activities average daily volumes	 	1,595	 	765	

(1)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period. 
        Average daily volumes from our tariff activities increased over 100% to approximately 1.6 million barrels per day. Almost all of the increase in the current year quarter is due to volumes transported on the pipelines acquired in 2004 and 2003. Volumes on all other pipeline systems remained relatively unchanged. 
        Total revenues from our pipeline operations were approximately $222.8 million and $155.8 million for the three months ended June 30, 2004 and 2003, respectively. An increase in revenues from tariff activities accounted for $45.7 million of the increase. Additionally, our margin activities increased by approximately $21.3 million in the second quarter of 2004. This increase was related to higher average prices for crude oil sold and transported on our San Joaquin Valley ("SJV") gathering system in the 2004 period as compared to the 2003 period, partially offset by lower buy/sell volumes. Because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. 
        Revenues from our tariff activities increased approximately 119% or $45.7 million. The following table reflects our revenues from our tariff activities by year of acquisition for comparison purposes: 
 	 	Three months ended
June 30,
	
 	 	2004
	 	2003
	
 	 	(in millions)	
Tariff activities revenues(1)	 	 	 	 	 	 	
 	2004 acquisitions	 	$	38.6	 	$	—	
 	2003 acquisitions	 	 	9.6	 	 	2.8	
 	All other pipeline systems	 	 	35.8	 	 	35.5	
 	 		 		
 	Total tariff activities	 	$	84.0	 	$	38.3	

(1)
Revenues include intersegment amounts. 

        The increase in the second quarter of 2004 is predominately related to the inclusion of $26.6 million of revenues from the pipelines acquired in the Link acquisition and $12.0 of revenues 
29

from other businesses acquired in 2004. Revenues from pipeline systems acquired in 2003 have increased to $9.6 million from $2.8 million. The increase is primarily the result of the inclusion in the second quarter of 2004 of several pipeline systems that were acquired during or after the second quarter of 2003. See "Acquisitions." Revenues from all other pipeline systems were relatively flat between years. 
        Field operating costs increased to $31.9 million in the second quarter of 2004 from $14.2 million in the second quarter of 2003. This increase is predominately related to our continued growth, primarily from the Link acquisition, and is comprised primarily of higher payroll and utility costs. 
        Segment G&A expenses increased approximately $5.8 million between comparable periods, primarily as a result of our Link acquisition coupled with the percentage of indirect costs allocated to the pipeline operations segment continuing to increase in the 2004 period as our pipeline operations have grown. G&A costs have also increased because of increased headcount resulting from continued growth and higher costs related to Sarbanes-Oxley requirements. Including the impact of the items discussed above, segment profit was approximately $47.7 million in the second quarter of 2004, or almost double the $24.2 million reported for the quarter ended June 30, 2003. 
Gathering, Marketing, Terminalling and Storage Operations 
        Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased crude oil and LPG volumes, plus the sale of additional barrels exchanged through buy/sell arrangements entered into to supplement the margins of the gathered and bulk-purchased volumes. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and the sale, revenues and costs related to purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. For example, our revenues increased approximately 93% in the second quarter of 2004 compared to the second quarter of 2003, while our segment profit decreased 30% in the same period. For the second quarter of 2004, this decrease in segment profit relates primarily to the noncash SFAS 133 mark-to-market loss as discussed further below. Approximately 50% of the increase in revenues related to increased sales volumes and the remaining 50% of the increase resulted from higher average prices in the 2004 period. The increase in sales volume primarily related to increased lease gathered barrels during the current quarter of approximately 215,000 barrels per day, primarily due to the Link acquisition. 
        Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in lease gathered volumes and LPG sales volumes. However, although the Link acquisition increased lease gathered barrels and revenues, there was not a corresponding contribution to segment profit as the lease gathered barrels primarily support the pipeline operations. Although we believe that the combination of our lease gathering business and our storage assets provides a counter-cyclical balance, which provides stability in our margins, these margins are not fixed and may vary from period to period. In order to evaluate the performance of this segment, management focuses on the following metrics: (i) segment profit (ii) crude oil lease gathered volumes and LPG sales volumes and (iii) segment profit per barrel calculated on these volumes. 
        As of June 30, 2004, we owned and operated approximately 37.0 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 12.6 million barrels of our 37.0 million barrels of tankage is used primarily in our 
30

GMT&S Operations and the balance is used in our Pipeline Operations segment. On a stand-alone basis, segment profit from terminalling and storage activities is dependent on the throughput of 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 in an effort to counter-cyclically balance and hedge our gathering and marketing activities. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (when oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow. We believe that this combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our results of operations and cash flows. 
        During the second quarter of 2004, market conditions were generally favorable as the market was in backwardation and experienced periods of volatility. The NYMEX benchmark price of crude ranged from $42.38 to $33.30 during the quarter. The market conditions in the second quarter of 2003 were also favorable as there was relatively high volatility and strong backwardation throughout the quarter. During the second quarter of 2003, the NYMEX benchmark price of crude ranged from $32.50 to $25.04. The following table sets forth our operating results from our GMT&S Operations segment for the comparative periods indicated: 
 	 	Three months ended
June 30,
	 	
 	 	2004
	 	2003
	 	
Operating Results(1) (in millions)	 	 	 	 	 	 	 	
 	Revenues	 	$	4,941.3	 	$	2,566.1	 	
 	Purchases and related costs	 	 	(4,891.3	)	 	(2,521.2	)	
 	Field operating costs (excluding LTIP charge)	 	 	(27.2	)	 	(18.3	)	
 	LTIP charge—operations	 	 	—	 	 	—	 	
 	Segment G&A expenses (excluding LTIP charge)(2)	 	 	(9.3	)	 	(7.7	)	
 	LTIP charge—general and administrative	 	 	—	 	 	—	 	
 	 		 		 	
 	Segment profit	 	$	13.5	 	$	18.9	 	
 	 		 		 	
 	Noncash SFAS 133 impact(3)	 	$	(6.9	)	$	0.2	 	
 	 		 		 	
 	Maintenance capital	 	$	0.7	 	$	0.2	 	
 	 		 		 	
Average Daily Volumes (thousands of barrels per day)(4)	 	 	 	 	 	 	 	
Crude oil lease gathering	 	 	641	 	 	425	 	
Crude oil bulk purchases	 	 	149	 	 	88	 	
 	 		 		 	
 	Total	 	 	790	 	 	513	 	
 	 		 		 	
LPG sales(5)	 	 	21	 	 	16	 	

(1)
Revenues and purchases and related costs include intersegment amounts. 
(2)
Segment 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. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period. 
(3)
Amounts related to SFAS 133 are included in revenues and impact segment profit. 
31

(4)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period. 
(5)
Prior period volumes have been adjusted for consistency of comparison between years. Sales reflect only third party volumes. 
        Segment profit was approximately $13.5 million or a decrease of approximately 30% for the second quarter of 2004 as compared to the second quarter of 2003. The decrease in the 2004 period as compared to the 2003 period is primarily related to a non-cash mark-to-market loss of $6.9 million in the 2004 period compared to a non-cash mark-to-market gain of $0.2 million in the 2003 period. The non-cash mark-to-market loss included in the second quarter of 2004 is primarily related to: 
•
The reversal of approximately $2.6 million of the non-cash mark-to-market gain recognized in the first quarter of 2003. The reversal of this previously recognized gain was related to positions that were closed and cash settled during the quarter. These positions were attributable primarily to hedges of cash flows associated with tankage assets that are accomplished through futures contracts and options contracts. Because these arrangements will not necessarily result in physical delivery, they are not eligible for hedge accounting; and 
•
A loss of approximately $4.3 million due to a change in fair value of option contracts resulting from increased volatility related to fluctuations in market structure during the period. These strategies are similar to selling covered calls against our physical lease gathering activities and tankage assets. Changes in market structure impact the values of these derivative contracts, which are required under SFAS 133 to be marked-to-market. However, certain activities related to offsetting physical positions and assets do not qualify for mark-to-market under SFAS 133. We typically hold these options to expiration, thus executing these strategies based on the level of protection they offer to stabilize cash flows rather than dynamically buying and selling options for profit due to such factors as changes in their premiums due to the volatility of the market structure. 
        Field operating costs and segment G&A expenses both increased during the period. Field operating costs increased to approximately $27.2 million in the current period from $18.3 million in the prior year period primarily related to the Link acquisition. Segment G&A expenses increased to $9.3 million in the current period from $7.7 million in the 2003 period. The increase is primarily related to increased costs associated with increased headcount from continued growth and higher costs related to Sarbanes-Oxley requirements. These increases have been partially offset by a larger percentage of costs being allocated to the Pipeline segment as our Pipeline Operations segment continues to grow and commensurate with support activities provided to the pipeline operations by personnel predominantly involved in lease gathering activities. 
        The crude oil volumes gathered from producers, using our assets or third-party assets, has increased by approximately 50% during the second quarter of 2004. The increase is primarily related to the Link acquisition coupled with other acquisitions and organic growth, which has offset natural production declines. In addition, we marketed 21,000 barrels per day of LPG during the second quarter of 2004 compared to 16,000 barrels per day in the second quarter of 2003. Segment profit per barrel calculated based on our lease gathered crude oil and LPG barrels was $0.23 per barrel for the quarter ended June 30, 2004, compared to $0.48 for the quarter ended June 30, 2003. The inclusion of the non-cash mark-to-market loss of $6.9 million resulted in a decrease in the segment profit per barrel for the second quarter of 2004 of approximately $0.16. Additionally, segment profit per barrel was negatively impacted by lower segment profit per barrel on the lease gathered barrels added in the 2004 quarter from the Link acquisition. Per barrel profits related to the Link acquisition are lower as the gathering business primarily supported the pipeline operations. 
        Revenues from our GMT&S operations were approximately $4.9 billion and $2.6 billion for the quarters ended June 30, 2004 and 2003, respectively. As discussed above, revenues and costs related to purchases for the 2004 period were impacted by higher average prices and higher volumes as compared 
32

to the 2003 period. The average NYMEX price for crude oil was $38.28 per barrel and $28.96 per barrel for the quarter ended June 30, 2004 and 2003, respectively. 
Other Expenses 
Depreciation and Amortization 
        Depreciation and amortization expense was $16.0 million for the three months ended June 30, 2004, compared to $11.3 million for the three months ended June 30, 2003. The increase relates primarily to the assets from our 2004 acquisitions and our various 2003 acquisitions being included for the full quarter in 2004 versus only a part or none of the quarter in 2003. Additionally, several capital projects were completed during mid-to-late 2003 that were not included in second quarter 2003 depreciation expense. Amortization of debt issue costs was $0.7 million and $1.0 million in the second quarter of 2004 and 2003, respectively. 
Interest Expense 
        The amount of interest expense we recognize is primarily impacted by our average debt balances, the level and maturity of fixed rate debt and interest rates associated therewith, market interest rates and our interest rate hedging activities on floating rate debt. During the second quarter of 2004, our average debt balance was approximately $943 million. This balance consisted of fixed rate senior notes with a face amount totaling $450 million and borrowings under our revolving credit facilities averaging $493 million. During the comparable 2003 period, our average debt balance was approximately $515 million and consisted of fixed rate senior notes with a face amount of $200 million and borrowings under our revolving credit facilities of $315 million. The higher average debt balance in the 2004 period was primarily related to the portion of our acquisitions that were not refinanced with equity. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity. 
        During the fourth quarter of 2003, we refinanced our senior secured credit facilities with new senior unsecured credit facilities, issued $250 million of ten year senior unsecured notes and terminated interest rate hedging instruments with notional amounts totaling $150 million. The termination of these instruments was made in connection with the issuance of the ten-year notes. The net result of the changes to our debt structure and our interest rate hedging instruments was an increase in the average amount of fixed rate debt outstanding in the second quarter of 2004 to approximately 48% as compared to approximately 39% in the second quarter of 2003. The new senior unsecured credit facilities reduced the interest rate on our credit facilities by approximately 100 basis points compared to the senior secured facility. In addition, during these two periods the average three-month LIBOR rate rose to 1.3% in 2004 from 1.2% in 2003. 
        The net impact of the items discussed above was an increase in interest expense in the second quarter of 2004 of approximately $1.5 million to a total of $10.0 million. The higher average debt balance in the 2004 period resulted in additional interest expense of approximately $4.6 million, while at the same time our commitment and other fees decreased by approximately $0.6 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 4.2% for the 2004 period compared to 6.1% for the 2003 period. The lower weighted average rate decreased interest expense by approximately $2.5 million in the second quarter of 2004 compared to the second quarter of 2003. 
33

Six Months Ended June 30, 2004 and 2003 
        For the six months ended June 30, 2004, we reported consolidated net income of $63.6 million on total revenues of $8.9 billion compared to net income for the same period in 2003 of $47.7 million on total revenues of $6.0 billion. The following table reflects our results of operations and maintenance capital for each segment (note that each of the items in the following table excludes depreciation and amortization): 
 	 	Pipeline
	 	GMT&S
	 	
 	 	(in millions)	 	
Six Months Ended June 30, 2004(1)	 	 	 	 	 	 	 	
Revenues	 	$	412.1	 	$	8,572.6	 	
Purchases	 	 	(269.6	)	 	(8,464.2	)	
Field operating costs (excluding LTIP charge)	 	 	(51.2	)	 	(45.7	)	
LTIP charge—operations	 	 	(0.1	)	 	(0.4	)	
Segment G&A expenses (excluding LTIP charge)(2)	 	 	(16.3	)	 	(18.7	)	
LTIP charge—general and administrative	 	 	(1.7	)	 	(2.0	)	
 	 		 		 	
Segment profit	 	$	73.2	 	$	41.6	 	
 	 		 		 	
Noncash SFAS 133 impact(3)	 	$	—	 	$	0.5	 	
 	 		 		 	
Maintenance capital	 	$	2.1	 	$	1.0	 	

Six Months Ended June 30, 2003(1)	

 	

 	
 	
Revenues	 	$	324.8	 	$	5,689.3	 	
Purchases	 	 	(243.6	)	 	(5,591.9	)	
Field operating costs	 	 	(27.7	)	 	(38.0	)	
Segment G&A expenses(2)	 	 	(9.1	)	 	(16.1	)	
 	 		 		 	
Segment profit	 	$	44.4	 	$	43.3	 	
 	 		 		 	
Noncash SFAS 133 impact(3)	 	$	—	 	$	1.1	 	
 	 		 		 	
Maintenance capital	 	$	3.8	 	$	0.4	 	

(1)
Revenues and purchases include intersegment amounts. 
(2)
Segment 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. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period. 
(3)
Amounts related to SFAS 133 are included in revenues and impact segment profit.
34

Pipeline Operations 
        The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated: 
 	 	Six months ended June 30,
	 	
 	 	2004
	 	2003
	 	
Operating Results(1) (in millions)	 	 	 	 	 	 	 	
 	Revenues	 	 	 	 	 	 	 	
 	 	Tariff activities	 	$	130.9	 	$	72.1	 	
 	 	Pipeline margin activities	 	 	281.2	 	 	252.7	 	
 	 		 		 	
 	Total pipeline operations revenues	 	 	412.1	 	 	324.8	 	
 	
Costs and Expenses	

 	

 	
 	
 	 	Pipeline margin activities purchases	 	 	(269.6	)	 	(243.6	)	
 	 	Field operating costs (excluding LTIP charge)	 	 	(51.2	)	 	(27.7	)	
 	 	LTIP charge—operations	 	 	(0.1	)	 	—	 	
 	Segment G&A expenses (excluding LTIP charge)(2)	 	 	(16.3	)	 	(9.1	)	
 	LTIP charge—general and administrative	 	 	(1.7	)	 	—	 	
 	 		 		 	
 	Segment profit	 	$	73.2	 	$	44.4	 	
 	 		 		 	
 	Maintenance capital	 	$	2.1	 	$	3.8	 	

Average Daily Volumes (thousands of barrels per day)(3)	

 	

 	
 	
 	Tariff activities	 	 	 	 	 	 	 	
 	 	All American	 	 	57	 	 	61	 	
 	 	Basin	 	 	273	 	 	245	 	
 	 	Link acquisition	 	 	185	 	 	—	 	
 	 	Capline	 	 	112	 	 	—	 	
 	 	Other domestic	 	 	408	 	 	261	 	
 	 	Canada	 	 	250	 	 	181	 	
 	 		 		 	
 	Total tariff activities	 	 	1,285	 	 	748	 	
 	Pipeline margin activities	 	 	73	 	 	81	 	
 	 		 		 	
 	 	 	Total	 	 	1,358	 	 	829	 	

(1)
Revenues and purchases include intersegment amounts. 
(2)
Segment 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. 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 total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.
        Total average daily volumes transported were approximately 1.4 million barrels per day and 0.8 million barrels per day for the six months ended June 30, 2004 and 2003, respectively. The increase relates to our tariff activities. As discussed above, we have completed a number of acquisitions during 
35

2004 and 2003 that have impacted the results of operations. The following table reflects our total average daily volumes from our tariff activities by year of acquisition for comparison purposes: 
 	 	Six months ended
June 30,
	
 	 	2004
	 	2003
	
 	 	(thousands of barrels per day)	
Tariff activities(1)	 	 	 	 	
 	2004 acquisitions	 	396	 	—	
 	2003 acquisitions	 	166	 	33	
 	All other pipeline systems	 	723	 	715	
 	 		 		
 	Total tariff activities average daily volumes	 	1,285	 	748	

(1)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.
        Average daily volumes from our tariff activities increased 0.5 million barrels per day to approximately 1.3 million barrels per day. Almost all of the increase in the current year quarter is due to volumes transported on the pipelines acquired in 2004 and 2003. Volumes on all other pipeline systems were relatively unchanged. 
        Total revenues from our pipeline operations were approximately $412.1 million and $324.8 million for the six months ended June 30, 2004 and 2003, respectively. An increase in revenues from tariff activities accounted for $58.8 million of the increase. Additionally, our margin activities increased by approximately $28.5 million in the first half of 2004. This increase was related to higher average prices for crude oil sold and transported on our SJV gathering system in the 2004 period as compared to the 2003 period, partially offset by lower buy/sell volumes. Because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. Volumes transported on the SJV system have decreased from the 2003 period. This is primarily related to a normalizing of volumes transported in the first quarter of 2004 as the first quarter of 2003 included additional shipments that typically move on other pipelines. These volumes shifted to the SJV system in 2003 because of maintenance being performed on a refinery during that time period. 
        Revenues from our tariff activities increased approximately 82% or $58.8 million. The following table reflects our revenues from our tariff activities by year of acquisition for comparison purposes: 
 	 	Six months ended
June 30,
	
 	 	2004
	 	2003
	
 	 	(in millions)	
Tariff activities revenues(1)	 	 	 	 	 	 	
 	2004 acquisitions	 	$	41.9	 	$	—	
 	2003 acquisitions	 	 	17.3	 	 	4.0	
 	All other pipeline systems	 	 	71.7	 	 	68.1	
 	 		 		
 	Total tariff activities	 	$	130.9	 	$	72.1	

(1)
Revenues include intersegment amounts. 
        The increase in the first half of 2004 is predominately related to the inclusion of $26.6 million of revenues from the pipelines acquired in the Link acquisition and $15.3 of revenues from other 
36

businesses acquired in 2004. Revenues from pipeline systems acquired in 2003 have increased to $17.3 million from $4.0 million. The increase is primarily the result of the inclusion in the first half of 2004 of several pipeline systems that were acquired after or during the first half of 2003. See "Acquisition Activities." Revenues from all other pipeline systems increased approximately $3.6 million to $71.7 million. The increase is primarily related to increased volumes on our Basin pipeline system and a $1.4 million favorable impact resulting from the decrease in the Canadian dollar to U.S. dollar exchange rate to an average of 1.34 to 1 for the first half of 2004, from an average of 1.45 to 1 for the first half of 2003. 
        Field operating costs increased to $51.3 million in the first half of 2004 from $27.7 million in the first half of 2003. This increase is predominately related to our continued growth, primarily from acquisitions, and is comprised primarily of higher payroll and utility costs. 
        Segment G&A expenses increased approximately $8.9 million between comparable periods, primarily as a result of our Link acquisition along with a $1.7 million accrual related to the probable vesting of unit grants under our Long-Term Incentive Plan ("LTIP"). G&A costs have also increased because of increased headcount resulting from continued growth and higher costs related to Sarbanes-Oxley requirements. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has increased in the 2004 period as our pipeline operations have grown. Including the impact of the items discussed above, segment profit was approximately $73.2 million for the six months ended June 30, 2004, an increase of 65% as compared to the $44.4 million reported for the six months ended June 30, 2003. Segment profit includes a $0.8 million favorable impact resulting from the decrease in the average Canadian dollar to U.S. dollar exchange rate for the 2004 period as compared to the 2003 period. 
Gathering, Marketing, Terminalling and Storage Operations 
        Our revenues from gathering and marketing activities increased approximately 51% in the first half of 2004 compared to the first half of 2003, while our segment profit decreased approximately 3% in the same period. Approximately 55% of the increase in revenues related to increased sales volumes and the remaining 45% of the increase resulted from higher average prices in the 2004 period. The increase in sales volume primarily related to increased lease gathered barrels resulting primarily from the Link acquisition. 
        During the first half of 2004, market conditions were generally favorable as the market was in relatively strong backwardation and experienced periods of volatility. The NYMEX benchmark price of crude ranged from $42.38 to $32.20 during the period. The market conditions in the first half of 2003 were more favorable as there was relatively high volatility and strong backwardation throughout the period. Additionally, cold weather during the first quarter of 2003 resulted in increased sales and higher margins in our LPG activities. During the first half of 2003, the NYMEX benchmark price of 
37

crude oil ranged from $39.99 to $25.04. The following table sets forth our operating results from our GMT&S Operations segment for the comparative periods indicated: 
 	 	Six months ended
June 30,
	 	
 	 	2004
	 	2003
	 	
Operating Results(1) (in millions)	 	 	 	 	 	 	 	
 	Revenues	 	$	8,572.6	 	$	5,689.3	 	
 	Purchases and related costs	 	 	(8,464.2	)	 	(5,591.9	)	
 	Field operating costs (excluding LTIP charge)	 	 	(45.7	)	 	(38.0	)	
 	LTIP charge—operations	 	 	(0.4	)	 	—	 	
 	Segment G&A expenses (excluding LTIP charge)(2)	 	 	(18.7	)	 	(16.1	)	
 	LTIP charge—general and administrative	 	 	(2.0	)	 	—	 	
 	 		 		 	
 	Segment profit	 	$	41.6	 	$	43.3	 	
 	 		 		 	
 	Noncash SFAS 133 impact(3)	 	$	0.5	 	$	1.1	 	
 	 		 		 	
 	Maintenance capital	 	$	1.0	 	$	0.4	 	
 	 		 		 	
Average Daily Volumes (thousands of barrels per day)(4)	 	 	 	 	 	 	 	
Crude oil lease gathering	 	 	550	 	 	430	 	
Crude oil bulk purchases	 	 	135	 	 	78	 	
 	 		 		 	
 	Total	 	 	685	 	 	508	 	
 	 		 		 	
LPG sales(5)	 	 	40	 	 	35	 	

(1)
Revenues and purchases and related costs include intersegment amounts. 
(2)
Segment 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. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period. 
(3)
Amounts related to SFAS 133 are included in revenues and impact segment profit. 
(4)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period. 
(5)
Prior period volumes have been adjusted for consistency of comparison between years. Sales reflect only third party volumes.
        Additionally, field operating costs and segment G&A expenses both increased during the period. Field operating costs increased to approximately $46.1 million in the current period from $38.0 million in the prior year period. This increase is primarily related to the Link acquisition. Also included is an approximately $0.4 million LTIP charge in the 2004 period. Segment G&A expenses increased to $20.7 million in the current period from $16.1 million in the 2003 period. The increase is primarily related to the inclusion of the $2.0 million LTIP charge in the 2004 period and increased headcount from continued growth and higher costs related to Sarbanes-Oxley requirements, but is partially offset by lower costs being allocated to our GMT&S segment as our Pipeline Operations segment continues to grow and commensurate with support activities provided to the pipeline operations by personnel predominantly involved in lease gathering activities. 
        The crude oil volumes gathered from producers, using our assets or third-party assets, has increased by 28% during the first half of 2004. The increase is related to the Link acquisition and organic growth and other acquisitions, which has offset natural production declines. In addition, we marketed 40,000 barrels per day of LPG during the first six months of 2004 compared to 35,000 barrels per day in the first six months of 2003. Segment profit per barrel calculated based on our lease gathered crude oil and LPG sales volumes was $0.39 per barrel for the six months ended June 30, 2004, compared to $0.52 for the six months ended June 30, 2003. The impact of change in the non-cash 
38

SFAS 133 mark-to-market for the first half of 2004 as compared to the first half of 2003 was a decrease in segment profit per barrel of approximately $0.02. Additionally, segment profit per barrel was negatively impacted by lower segment profit per barrel on the lease gathered barrels added in the 2004 quarter from the Link acquisition. Per barrel profits related to the Link acquisition are lower because the gathering business primarily supported the pipeline operations. 
        Revenues from our gathering, marketing, terminalling and storage operations were approximately $8.6 billion and $5.7 billion for the six months ended June 30, 2004 and 2003, respectively. As discussed above, revenues and costs related to purchases for the 2004 period were impacted by higher average prices and higher volumes as compared to the 2003 period. The average NYMEX price for crude oil was $36.78 per barrel and $31.42 per barrel for the six months ended June 30, 2004 and 2003, respectively. 
Other Expenses 
Depreciation and Amortization 
        Depreciation and amortization expense was $29.1 million for the six months ended June 30, 2004, compared to $22.2 million for the six months ended June 30, 2003. The increase relates primarily to the assets from our 2004 acquisitions and our various 2003 acquisitions being included for the full six months in 2004 versus only a part or none of the six months in 2003. Additionally, several capital projects were completed during mid-to-late 2003 that were not included in the first six months of 2003 depreciation expense. Amortization of debt issue costs was $1.2 million and $2.0 million in the first half of 2004 and 2003, respectively. 
Interest Expense 
        During the first half of 2004, our average debt balance was approximately $771 million. This balance consisted of fixed rate senior notes with a face amount totaling $450 million and borrowings under our revolving credit facilities averaging $321 million. During the comparable 2003 period, our average debt balance was approximately $520 million and consisted of fixed rate senior notes with a face amount of $200 million and borrowings under our revolving credit facilities of $320 million. The higher average debt balance in the 2004 period was primarily related to the portion of our acquisitions that were not refinanced with equity. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity. 
        The net result of the changes to our debt structure and our interest rate hedging instruments mentioned above was an increase in the average amount of fixed rate debt outstanding in the first half of 2004 to approximately 58% as compared to approximately 38% in the first half of 2003. The new senior unsecured credit facilities reduced the interest rate on our credit facilities by approximately 100 basis points compared to the senior secured facility. In addition, during these two periods the average three-month LIBOR rate declined to 1.2% in 2004 from 1.3% in 2003. 
        The net impact of the items discussed above was an increase in interest expense in the first half of 2004 of approximately $1.8 million to a total of $19.5 million. The higher average debt in the 2004 period resulted in additional interest expense of approximately $6.2 million, while at the same time our commitment and other fees decreased by approximately $1.4 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 4.9% for the first half of 2004 compared to 6.1% for the first half of 2003. The lower weighted average rate decreased interest expense by approximately $3.0 million in the first half of 2004 compared to the first half of 2003. 
39

Outlook 
        This "Outlook" section and the section captioned "Forward Looking Statements and Associated Risks" identify certain matters of risk and uncertainty that may affect our financial performance and results of operations in the future. 
        Ongoing Acquisition Activities.    Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstream crude oil assets. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. We can give 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. 
        Link Energy LLC Acquisition.    The completion and integration of the Link acquisition began impacting our operating results in the second quarter of 2004. We anticipate that the assets acquired in the acquisition will generate a baseline cash flow from operations of approximately $6.25 million per quarter or approximately $25.0 million annually. In addition, we believe that we will realize annual cost savings and synergies of approximately $27.0 million to $32.0 million that are expected to be phased in by the first quarter of 2005 as the business is fully integrated. However, we also anticipate certain one-time expense items in the initial six to nine month period as a result of integration costs, as well as costs associated with regulatory requirements. These costs will have a negative impact in the short-term on our baseline projection for the acquisition. 
        Credit Rating.    In July 2004, Standard & Poor's removed us from creditwatch with negative implications and affirmed their BBB- stable senior unsecured rating (an investment grade rating). Also in July 2004, Moody's Investors Service revised their review of our senior unsecured rating from a review with direction uncertain to a review for possible upgrade. We are currently rated Ba1, which is Moody's highest non-investment grade rating. You should note that a credit rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time. 
Liquidity and Capital Resources 
Liquidity 
        Cash generated from operations and our credit facilities are our primary sources of liquidity. At June 30, 2004, we had a working capital deficit of approximately $26.2 million, approximately $342.6 million of availability under our committed revolving credit facilities and $168.0 million of unused capacity under our uncommitted hedged inventory facility. Usage of the credit facilities is subject to compliance with covenants. We believe we are currently in compliance with all covenants. 
        As discussed above, we closed the Link acquisition on April 1, 2004. The acquisition was funded with cash on hand, borrowings under a new $200 million, 364-day credit facility and borrowings under our existing revolving credit facilities. The new credit facility contains a twelve-month term out option, exercisable at our election, at the end of the primary term and bears interest at a rate of LIBOR plus a margin ranging from .625% to 1.25%, depending on our credit rating. In connection with the Link acquisition, on April 15, 2004, we completed the private placement of 3,245,700 units of Class C common units to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors for $30.81 per unit. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, was approximately $101 million, and was used to reduce the balance outstanding under our existing revolving credit facilities. We have committed to use net proceeds from future debt and equity offerings to retire or reduce the amount outstanding under the new $200 million, 364-day credit facility. 
40

        In the third quarter of 2004, we completed a public offering of 4,904,000 common units for $33.25 per unit. The offering resulted in gross proceeds of approximately $163.1 million from the sale of units and approximately $3.3 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $7.3 million. Net proceeds of $159.1 million were used to permanently reduce outstanding borrowings under the new $200 million, 364-day credit facility as discussed above (see Note 4). 
        On August 5, 2004, we sold $175 million of 4.75% Senior Notes due 2009 and $175 million of 5.88% Senior Notes due 2016. The 4.75% notes were sold at 99.551% and the 5.88% notes were sold at 99.345% of face value. We expect to close the sale on August 12, 2004, with proceeds after initial purchaser discount and offering costs of approximately $345.3 million. We intend to use the proceeds to repay amounts outstanding under our credit facilities, including the remaining balance under the $200 million, 364-day facility we used to fund the Link acquisition, and for general partnership purposes. 
        We are in the process of increasing the capacity of our uncommitted senior secured hedged inventory facility from $200 million to $300 million, primarily as a result of increased crude oil prices and an increase in our crude oil storage capacity as a result of acquisitions. We expect to complete the increase during the third quarter. 
Capital Expenditures 
        We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations, credit facility borrowings, the issuance of senior unsecured notes and the sale of additional common units. 
        We expect to spend approximately $128.1 million on expansion capital projects during 2004. This includes our original estimate of expansion capital, newly announced projects and expansion capital associated with the Link acquisition. Our 2004 expansion capital projects include the following notable projects with the estimated cost for the entire year (in millions). 
Project
	 	 	
Cushing to Caney pipeline project	 	$	33.6	
Cushing Phase IV expansion	 	 	10.0	
Capital projects and upgrades associated with the Link acquisition	 	 	19.1	
Upgrade and expansion related to acquisitions made in 2003	 	 	24.8	
Capital projects and upgrades associated with the CalVen acquisition	 	 	7.1	
Iatan System expansion	 	 	6.6	
Other	 	 	26.9	
 	 		
 	 	$	128.1	
 	 		
        In addition, we expect to spend approximately $14.1 million on maintenance capital projects during 2004. For the first half of 2004, we have incurred approximately $32.0 million related to expansion capital projects and approximately $3.1 million on maintenance capital projects. 
        We will also have additional cash funding requirements related to the Link acquisition. The aggregate estimated purchase price for the Link acquisition is approximately $326.1 million, of which approximately $268.0 million (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) was funded at closing. The approximately $58.0 million balance includes acquisition related costs and net liabilities assumed. 
41

        We believe that we have sufficient liquid assets, cash flow 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 affect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity. 
Cash Flows 
 	 	Six Months
Ended
June 30,
	 	
 	 	2004
	 	2003
	 	
 	 	(in millions)	 	
Cash provided by (used in):	 	 	 	 	 	 	 	
 	Operating activities	 	$	147.1	 	$	204.8	 	
 	Investing activities	 	 	(474.6	)	 	(139.8	)	
 	Financing activities	 	 	334.0	 	 	(63.0	)	
        Operating Activities.    The primary drivers of our cash flow from operations are (i) the collection of amounts related to the sale of crude oil and LPG and the transportation of crude oil for a fee and (ii) the payment of amounts related to the purchase of crude oil and LPG and other expenses, principally field operating costs, general and administrative expenses and interest expense. The cash settlement from the purchase and sale of crude oil during any particular month typically occurs within thirty days from the end of the month, except in the months that we store inventory because of contango market conditions or in months that we increase linefill. The storage of crude oil in periods of a contango market can have a material impact on our cash flows from operating activities for the period we pay for and store the crude oil and the subsequent period that we receive proceeds from the sale of the crude oil. When we store crude oil, we borrow on our credit facilities to pay for the crude oil and the impact on operating cash flow is negative. Conversely, cash flow from operations increases in the period we collect the cash from the sale of the stored crude oil. To a lesser extent, our cash flow from operating activities is also impacted by the level of LPG inventory stored at period end. Cash flow from operations was $147.1 million and $204.8 million in 2004 and 2003, respectively. 
        Investing Activities.    Net cash used in investing activities in 2004 and 2003 consisted predominantly of cash paid for acquisitions. Net cash used in 2004 was $474.6 million and was primarily comprised of (i) $142.3 million paid for the Capline and Capwood Pipeline Systems acquisition (a deposit had been paid in December 2003) (ii) approximately $280 million paid for the Link acquisition, (iii) approximately $19 million paid for the CalVen acquisition and (iv) $32.2 million paid for additions to property and equipment. Included in cash paid for additions to property and equipment is (i) approximately $6.6 million related to the Cushing Phase IV expansion, (ii) approximately $5.0 million related to the Iatan System expansion, (iii) approximately $3.0 million of maintenance capital, (iv) and approximately $1.2 million related to the Cushing to Caney pipeline project. Net cash used in investing activities in 2003 includes approximately $79.6 million paid for acquisitions and approximately $37.5 million for additions to property and equipment. In addition, approximately $28.5 million was paid for linefill on assets that we own. 
        Financing Activities.    Cash provided by financing activities in 2004 was approximately $334.0 million and was comprised of (i) approximately $100.9 million of proceeds from the issuance of Class C common units, (ii) net short and long-term borrowings under our revolving credit facility of approximately $403.7 million used primarily to fund the purchase price of the Capline and Link acquisitions, (iii) net repayments under our short-term letter of credit and hedged inventory facility of approximately $96.1 million resulting from the collection of receivables related to prior year sales of inventory that was stored because of contango market conditions and (iv) $72.7 million of distributions 
42

paid to common unitholders and the general partner. Cash used in financing activities in 2003 consisted of (i) approximately $63.9 million of proceeds from the issuance of common units used to pay down outstanding balances on the revolving credit facility, (ii) $58.8 million of distributions paid to unitholders and the general partner, (iii) a $7.0 million repayment of a maturity under our senior secured term loan, (iv) net long-term borrowings under our revolving credit facilities of $29.1 million, and (v) net short-term debt repayments of $90.2 million primarily from the proceeds of inventory sales. 
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 ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Department of Commerce. In 2002, we determined that we may 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 received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, we received a request from the BIS for additional information. 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 this matter. 
        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.    A pipeline, terminal or other facility may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The trend appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities. 
43

        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. 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 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. 
Recent Accounting Pronouncements 
        In March 2004, the Emerging Issues Task Force issued Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128." EITF 03-06 addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. Although the adoption of EITF 03-06 did not result in a change in the Partnership's earnings per limited partner unit for any of the periods presented, the adoption may have an impact on earnings per limited partner unit in future periods if net income exceeds distributions. The effect of applying EITF 03-06 on prior periods was not material except for the year ended December 31, 2000, which has been restated as shown below. 
Basic and Diluted Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle per Limited Partner Unit:
 	 	2000
	
Prior to the adoption of SFAS 145(1) or EITF 03-06	 	$	2.64	

After the adoption of SFAS 145 but prior to the adoption of EITF 03-06	
 	
$	
2.20	

After the adoption of both SFAS 145 and EITF 03-06	
 	
$	
2.13	

(1)
SFAS 145 "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". 
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 our pipeline systems; 
44

•
declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers; 
•
the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate; 
•
demand for various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements; 
•
fluctuations in refinery capacity in areas supplied by our transmission lines; 
•
the effects of competition; 
•
the success of our risk management activities; 
•
the impact of crude oil price fluctuations; 
•
the availability of, and ability to consummate, acquisition or combination opportunities; 
•
successful integration and future performance of acquired assets; 
•
continued creditworthiness of, and performance by, our counterparties; 
•
our levels of indebtedness and our ability to receive credit on satisfactory terms; 
•
maintenance of our credit rating and ability to receive open credit from our suppliers; 
•
successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil; 
•
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, insurance or existing reserves; 
•
fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our LTIP; 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/A Amendment No. 1 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 2003 Form 10-K/A Amendment No. 1. There have not been any material changes in that information other than those discussed below. 
        As of June 30, 2004 and December 31, 2003 the fair value of our crude oil futures contracts was approximately $18.6 million and $7.5 million respectively. A 10% price decrease would result in a decrease in fair value of $1.4 million and $6.4 million at June 30, 2004 and December 31, 2003, respectively. 
45

Item 4. CONTROLS AND PROCEDURES 
        We maintain "disclosure controls and procedures," which we refer to as our "DCP." The purpose of our DCP is to provide reasonable assurance that (i) information is recorded, processed, summarized and reported in time to allow for 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. 
        Applicable SEC rules require our management to evaluate, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our DCP as of June 30, 2004. Management (including our Chief Executive Officer and Chief Financial Officer) has evaluated the effectiveness of the design and operation of our DCP as of June 30, 2004, and has found our DCP to be effective in providing reasonable assurance of 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 disclose any change in our internal control over financial reporting ("internal control") that occurred during the second quarter and that has materially affected, or is reasonably likely to materially affect, our internal control. There were none. However, in the process of documenting and testing our internal control in connection with future compliance with Rule 13a-15(c) under the Exchange Act of 1934, as amended (required by Section 404 of the Sarbanes/Oxley Act of 2002) we have made changes, and will to continue to make changes, to refine and improve our internal control. 
        The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a) are filed with this report as exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §1350 are furnished with this report as exhibits 32.1 and 32.2. 

PART II. OTHER INFORMATION 
Item 1. LEGAL PROCEEDINGS 
        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 ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Department of Commerce. In 2002, we determined that we may 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 received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004. In August 2004, we received a request from the BIS for additional information. 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 this matter. 
        Alfons Sperber v. Plains Resources Inc., et. al.    On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unit holders, asserts breach of fiduciary duty and breach of contract claims against the 
46

Partnership, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. The complaint seeks to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. Attorneys for the parties have executed a memorandum of understanding with respect to a potential settlement of this lawsuit. The settlement, which is subject to final documentation and other customary conditions (including a full release with prejudice of the settled claims and approval by the court), would include the payment by defendants of plaintiffs' attorney fees and costs. We consider our cost to settle this matter to be immaterial. 
        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, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES 
        Securities Not Registered Under the Securities Act.    In connection with the acquisition discussed in Note 2, on April 15, 2004 we issued 3,245,700 Class C common units for $30.81 per unit in a private placement to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million and were used to reduce the balance outstanding under our revolving credit facilities. The Class C common units are unlisted securities that are pari passu in voting and distribution rights with the Partnership's publicly traded common units. The Class C common units are similar in many respects to the Partnership's Class B common units. The Class C units are convertible into common units upon approval by the holders of a majority of the common units. Beginning six months from the closing of the private placement, the Class C unitholders may request that the Partnership call a meeting of its common unitholders to consider approval of the conversion of the Class C units into common units. If the approval of the conversion is not obtained within 120 days of the request, the Class C unitholders will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit. If the approval of the conversion is not secured within 90 days after the end of the 120-day period, the distribution right increases to 115%. 
        Issuer Purchases of Equity Securities.    During June 2004, we purchased 6,250 common units on the open market at an average price of $32.36 per unit (including applicable trade commissions). The purchased units were used to satisfy obligations under our LTIP and are not part of a publicly announced repurchase plan or program. 

Item 3. DEFAULTS UPON SENIOR SECURITIES 
        None 

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 
        None 

Item 5. OTHER INFORMATION 
        Communications with Directors.    Our security holders and other interested parties may communicate with one or more of our directors (including any committee or the non-management directors as a group) by mail in care of either Tim Moore, General Counsel and Secretary or Sharon Spurlin, Director of Internal Audit, Plains All American Pipeline, L.P., 333 Clay Street, Suite 1600, 
47

Houston, Texas, 77002. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded. 

Item 6. EXHIBITS AND REPORTS ON FORM 8-K 
A.
Exhibits 

*3.1	 	Amendment No. 1, dated as of April 15, 2004 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of June 27, 2001	

*3.2	
 	
Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004	

*3.3	
 	
Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004	

3.4	
 	
Second Amendment dated as of July 23, 2004 to Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC (Incorporated by reference to Exhibit 3.1 to the Partnership's Current Report on Form 8-K filed July 27, 2004)	

*4.1	
 	
Registration Rights Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income partners (QP), L.P., Kayne Anderson MLP Fund, L.P., Tortoise Energy Infrastructure Corporation, and Vulcan Energy II Inc., dated April 15, 2004	

*4.2	
 	
Class C Common Unit Purchase Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income partners (QP), L.P., Kayne Anderson MLP Fund, L.P., Tortoise Energy Infrastructure Corporation, and Vulcan Energy II Inc., dated March 31, 2004	

*10.1	
 	
Interim 364-Day Credit Facility dated April 1, 2004 among Plains All American Pipeline, L.P. and Bank One, N.A. and certain other lenders	

†10.2	
 	
Amended and Restated Marketing Agreement, dated as of July 23, 2004, among Plains Resources Inc., Calumet Florida Inc. and Plains Marketing, L.P.	

†10.3	
 	
Amended and Restated Omnibus Agreement, dated as of July 23, 2004, among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., Plains Pipeline, L.P., and Plains All American GP LLC.	

†10.4	
 	
Second Amendment dated as of April 20, 2004 to Credit Agreement dated as of November 21, 2003, as amended.	

†18.1	
 	
Letter re: change in accounting principle	

31.1	
 	
Certification of Principal Executive Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)	

31.2	
 	
Certification of Principal Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)	

32.1	
 	
Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.	
 	 	 	
48

32.2	
 	
Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350	

*
Incorporated by reference to the Partnership's Quarterly Report on Form 10-Q for the period ended March 31, 2004. 
†
Filed herewith. 
B.
Reports on Form 8-K. 

        A Current Report on Form 8-K was furnished on August 4, 2004 in connection with second quarter 2004 results and third and fourth quarter 2004 guidance. 
        A Current Report on Form 8-K was filed on July 27, 2004, with an amendment to the Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated as of June 8, 2001, as amended, attached as an exhibit. 
        A Current Report on Form 8-K was filed on July 23, 2004, with an underwriting agreement for an equity offering attached as an exhibit. 
        A Current Report on Form 8-K was filed on July 21, 2004, in connection with a change in accounting principle. 
        A Current Report on Form 8-K was filed on June 29, 2004, with an unaudited balance sheet of Plains AAP, L.P., as of March 31, 2004, attached as an exhibit. 
        A Current Report on Form 8-K was filed on June 16, 2004, in connection with the acquisition of substantially all of the operations of Link Energy LLC. 
        A Current Report on Form 8-K was furnished on June 16, 2004, in connection with disclosure of updated second quarter and second half of 2004 estimates and earnings guidance. 
        A Current Report on Form 8-K was furnished on April 28, 2004, in connection with disclosure of second quarter and second half of 2004 estimates and earnings guidance. 
        A Current Report on Form 8-K was filed on April 27, 2004, with an audited balance sheet of Plains AAP, L.P., as of December 31, 2003, attached as an exhibit. 
        A Current Report on Form 8-K was furnished on April 16, 2004, in connection with disclosure of our presentation to the IPAA Oil & Gas Investment Symposium. 
        A Current Report on Form 8-K was filed on April 15, 2004, in connection with disclosure of our acquisition of substantially all of the operations of Link Energy LLC. The related Purchase and Sale Agreement and Plan of Merger were attached as exhibits. 
        A Current Report on Form 8-K was filed on April 7, 2004, in connection with disclosure of the investigation by the Texas Attorney General's office of our acquisition of Link Energy. 
49

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: August 6, 2004	
 	
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: August 6, 2004	
 	
By:	
 	
/s/  PHIL KRAMER      

Phil Kramer, Executive Vice President and Chief Financial Officer of Plains All American GP LLC
(Principal Financial Officer)	
50

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EXHIBIT 10.2 

AMENDED AND RESTATED

CRUDE OIL MARKETING AGREEMENT

among

PLAINS RESOURCES INC.

CALUMET FLORIDA, LLC

and

PLAINS MARKETING, L.P. 

TABLE OF CONTENTS 
ARTICLE I DEFINITIONS	 	1	
 	1.1 Definitions	 	1	

ARTICLE II PURCHASE AND SALE	
 	
3	
 	2.1 Purchase and Sale	 	3	
 	2.2 Addition or Release of Properties or Sellers	 	3	
 	2.3 Delivery	 	4	
 	2.4 Price	 	4	
 	2.5 Payment	 	5	
 	2.6 General Provisions	 	5	
 	2.7 No Restrictions	 	5	

ARTICLE III RENEGOTIATION	
 	
5	

ARTICLE IV ADDITIONAL SERVICES	
 	
6	
 	4.1 Additional Services	 	6	
 	4.2 Sellers Indemnity	 	6	

ARTICLE V TERM	
 	
6	

ARTICLE VI REPRESENTATIONS AND WARRANTIES	
 	
7	
 	6.1 Representations and Warranties of Sellers	 	7	
 	6.2 Representations and Warranties of Buyer	 	8	

ARTICLE VII CREDIT REQUIREMENTS	
 	
8	

ARTICLE VIII SPECIFIED EVENTS	
 	
8	
 	8.1 Buyer Specified Events	 	8	
 	8.2 Seller Specified Events	 	9	
 	8.3 Early Termination	 	10	
 	8.4 Specified Damages	 	10	

ARTICLE IX FORCE MAJEURE	
 	
10	
 	9.1 Excuse for Nonperformance	 	10	
 	9.2 Definition	 	10	
 	9.3 Notice and Cure	 	10	

ARTICLE X GENERAL PROVISIONS	
 	
11	
 	10.1 No Survival of Representations and Warranties	 	11	
 	10.2 Headings	 	11	
 	10.3 Rights and Remedies Cumulative	 	11	
 	10.4 Entire Agreement; Supersedure	 	11	
 	10.5 Severability	 	11	
 	10.6 Choice of Law; Submission to Jurisdiction	 	11	
 	10.7 Binding Agreement; No Third-Party Beneficiaries	 	11	
 	10.8 No Agency	 	11	
 	10.9 Notice	 	11	
 	10.10 Effect of Waiver or Consent	 	12	
 	10.11 Assignment	 	12	
 	10.12 Counterparts	 	12	
 	10.13 Amendment or Modification	 	12	
 	10.14 Further Assurances	 	12	
 	10.15 Withholding or Granting of Consent	 	12	
 	10.16 U.S. Currency	 	12	
 	10.17 Laws and Regulations	 	12	
 	10.18 Construction of Agreement	 	12	
EXHIBITS 
        Exhibit A            Covered Properties 
        Exhibit B            Existing Contracts 
        Exhibit C            General Provisions 

CRUDE OIL MARKETING AGREEMENT 
        This CRUDE OIL MARKETING AGREEMENT (this "Agreement"), dated July 23, 2004 by and among PLAINS RESOURCES INC., a Delaware corporation ("Plains Resources"), CALUMET FLORIDA, INC., a Delaware corporation ("Calumet"), and PLAINS MARKETING, L.P., a Delaware limited partnership ("Buyer") amends and restates the Crude Oil Marketing Agreement dated November 23, 1998, by and among Plains Resources, PLAINS ILLINOIS INC., a Delaware corporation ("Plains Illinois"), STOCKER RESOURCES, L.P., a California limited partnership ("Stocker"), Calumet and Buyer. Plains Resources and Calumet are sometimes referred to herein individually as a "Seller" and collectively as the "Sellers." Sellers and Buyer are sometimes referred to herein individually as a "Party" and collectively as the "Parties." 
R E C I T A L S: 
        A.    Sellers own and produce crude oil from properties located within the lower 48 states of the United States. 
        B.    Sellers desire to sell and Buyer desires to purchase all of the crude oil that is produced and owned by Sellers from such properties. 
        NOW, THEREFORE, the Parties agree as follows: 

ARTICLE I
DEFINITIONS 
        1.1   Definitions. As used herein, the following terms shall have the following meanings: 
        "Affiliate" means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise. For clarity, Plains Exploration & Production Company and Plains Resources are not Affiliates of each other for purposes of this Agreement. 
        "Agreement" means this Agreement and all exhibits, schedules, amendments, modifications, and supplements to this Agreement. 
        "Anniversary Date" has the meaning assigned in Article III. 
        "Barrel" means forty-two (42) United States gallons of Crude Oil measured in accordance with the General Provisions. 
        "Business Day" means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the states of New York or Texas shall not be regarded as a Business Day. 
        "Buyer Specified Event" has the meaning assigned in Section 8.1. 
        "Calumet Contract" means the Crude Oil Purchase Contract dated as of November 18, 2003, between Buyer and Calumet Florida Division of Plains Resources (A/K/A Calumet Florida LLC). 
        "Conflicts Committee" means a committee of the Board of Directors of the General Partner composed entirely of two or more directors who are neither securityholders, officers nor employees of the General Partner nor officers, directors or employees of any Affiliate of the General Partner. 
        "Corporate Governance Documents" means, with respect to any Person, the Certificate or Articles of Incorporation, or Partnership Agreement (or their equivalents), the by-laws (or their equivalents), and the other corporate governance documents of such Person. 
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        "Crude Oil" means crude oil meeting the specifications set forth in the General Provisions. 
        "Defaulting Party" means (a) in the case of a Buyer Specified Event, Buyer, and (b) in the case of a Seller Specified Event, any Seller affected by such Seller Specified Event. 
        "Delivery Point" has the meaning assigned in Section 2.3. 
        "Effective Date" means the date of execution of this Agreement. 
        "Existing Contract" means any (i) third party crude oil sales contract to which a Seller or its properties are bound or (ii) any joint operating agreement governing a Seller's property if the operator is not a Seller, to the extent, in the case of both clause (i) and (ii) above, such contract or operating agreement existed as of (a) the Effective Date and is listed on Exhibit B or (b) the date on which such Seller becomes a Seller pursuant to Section 2.2 or the properties become subject to this Agreement pursuant to Section 2.2. 
        "Force Majeure" has the meaning assigned in Article IX. 
        "General Partner" means Plains All American GP LLC, a Delaware limited liability company, in its capacity as the general partner of Plains AAP, L.P. (the general partner of Plains All American Pipeline, L.P)., and its predecessors, successors and permitted assigns as the managing entity of Plains All American Pipeline, L.P. 
        "General Provisions" has the meaning assigned in Section 2.6. 
        "Governmental Requirements" means all judgments, orders, writs, injunctions, decrees, awards, laws, ordinances, statutes, regulations, rules, franchises, permits, certificates, licenses, authorizations, and the like of any government, or any commission, board, court, agency, instrumentality, or political subdivision thereof. 
        "Marketing and Administrative Fee" has the meaning assigned in Section 2.4. 
        "Marketing Area" means the lower 48 states of the United States, Alaska and the Outer Continental Shelf. 
        "Non-defaulting Party" means (i) in the case of a Buyer Specified Event, any Seller that is affected by such Buyer Specified Event, and (ii) in the case of a Seller Specified Event, Buyer. 
        "Partnership Entities" shall mean the General Partner, Plains All American Pipeline, L.P., Plains Marketing GP Inc., and any Affiliate directly or indirectly controlled by the General Partner, Plains All American Pipeline, L.P. or Plains Marketing GP Inc. 
        "Person" means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity. 
        "Plains Entities" means Plains Resources and any of its Affiliates, other than the Partnership Entities. 
        "Platt's P+ Average" means the arithmetic average of the Platt's Prices for P-Plus WTI during a Trading Cycle. 
        "Platt's Difference" means the arithmetic average for a Trading Cycle of the difference between the Platt's Prices of the applicable grade of crude to be exchanged (i.e. WTS, LLS, HLS, Eugene Island, Bonito, etc.) and the prompt month WTI. 
        "Platt's Prices" means the average of the price range of a particular grade of crude oil as published in the Crude Price Assessments table of Platt's Oilgram Price Report. 
        "Purchase Price" has the meaning assigned in Section 2.4. 
2

        "Sales Price" has the meaning assigned in Section 2.4. 
        "Seller Specified Event" has the meaning assigned in Section 8.2. 
        "Specified Event" means a Buyer Specified Event or a Seller Specified Event, as the case may be. 
        "Trading Cycle" means for a particular month of delivery, a cycle beginning on the 26th day of the second month preceding such month of delivery through the 25th day of the month preceding such month of delivery. 
        "Trade Location" has the meaning assigned in Section 2.4(b). 
        "Voting Stock" means securities of any class of Plains Resources entitling the holders thereof to vote on a regular basis in the election of members of the board of directors of Plains Resources. 

ARTICLE II
PURCHASE AND SALE 
        2.1   Purchase and Sale. Buyer hereby agrees to purchase and receive and Sellers hereby agree to sell and deliver all of the Crude Oil produced and owned by Sellers from properties located within the Marketing Area. Currently, such properties are set forth on Exhibit A attached hereto and incorporated herein. Exhibit A shall be promptly updated to add or delete, as the case may be, Crude Oil production dedicated to this Agreement. No Crude Oil shall be sold hereunder in contravention of an Existing Contract by such Seller or from such properties until the Existing Contract has expired or been terminated. 
        2.2   Addition or Release of Properties or Sellers. Crude Oil producing properties and Sellers shall be added or released from the terms and provisions of this Agreement upon the occurrence of the following events: 
        (a)   If a Person who owns Crude Oil producing properties within the Marketing Area becomes an Affiliate controlled by Plains Resources, Plains Resources shall cause such controlled Affiliate to become a Seller hereunder by executing and delivering a ratification of this Agreement to Buyer as soon as practicable after the date such Person became an Affiliate controlled by Plains Resources. 
        (b)   If a Seller acquires additional Crude Oil properties within the Marketing Area, such additional properties and the Crude Oil owned and produced therefrom by such Seller shall become subject to this Agreement as soon as practicable after the date of acquisition of such properties. 
        (c)   If a Seller, other than Plains Resources, ceases to be an Affiliate of Plains Resources, this Agreement shall terminate with respect to such Seller, its properties, and the Crude Oil produced therefrom, with such termination to be effective as soon as practicable following the date such Seller gives written notice to Buyer that it has ceased to be an Affiliate of Plains Resources; but in no event shall such properties cease to be subject to this Agreement prior to the termination of and to the extent of any agreement Buyer has previously entered into for the sale of Crude Oil attributable to production from such properties. 
        (d)   If a Seller sells, transfers or otherwise disposes of any of its properties or the interests therein that are within the Marketing Area, such properties or interests shall cease to be subject to this Agreement as soon as practicable following the date of such sale, transfer or disposition; but in no event shall such properties or interests cease to be subject to this Agreement prior to the termination of any agreement Buyer has previously entered into for the sale of Crude Oil attributable to production from such properties or interests. Buyer also agrees that it will give Sellers notice prior to entering into any such agreement with third parties for a term in excess of 
3

twelve months. Sellers will promptly, upon such notice, either approve or disapprove such agreement, in writing. Buyer will not sell any Crude Oil under such agreement without written approval from the relevant Sellers. 
        (e)   If a Seller and Buyer determine that it is impracticable for Buyer to continue to purchase Crude Oil from any property owned by such Seller within the Marketing Area, such Seller and Buyer may, by mutual written agreement with the concurrence of the Conflicts Committee, terminate this Agreement with respect to such properties. Thereafter, neither such Seller nor Buyer shall have any further obligations under this Agreement with respect to such properties. 
        (f)    Upon the occurrence of any of the foregoing events under subparagraphs (a), (b), (c), (d) or (e) above, the affected Seller shall give written notice to Buyer as soon as practicable and Exhibit A shall be revised to reflect the effect of such event. Upon request by any Party affected by such event, all Parties hereto shall execute and deliver to the requesting Party such documents and instruments as may be reasonably necessary to evidence additions or releases of Parties or properties to this Agreement. 
        (g)   Notwithstanding the provisions of subparagraphs (a) and (b) above, the addition of any Seller or properties to this Agreement shall be subject to any Existing Contract. Accordingly, no Crude Oil shall be sold hereunder in contravention of an Existing Contract by such Seller or from such properties until the Existing Contract has expired or been terminated. 
        2.3   Delivery. Delivery shall be made from the lease tankage on the properties, or such other point as is mutually agreed to and reflected on Exhibit A (a "Delivery Point"), into transportation facilities designated by Buyer. 
        2.4   Price. The price to be paid by Buyer for Crude Oil sold hereunder (the "Purchase Price") shall be equal to the Sales Price for each Barrel as determined in this Section 2.4 (or as otherwise agreed by Buyer and relevant Seller), less the sum of (i) a marketing and administrative fee of $.20 for each Barrel sold (the "Marketing and Administrative Fee") and (ii) with respect to Crude Oil that is not sold by Buyer at a Delivery Point, the reasonable out-of-pocket expenses (if any) incurred by Buyer to transport or exchange each Barrel of such Crude Oil; provided, however, that the Marketing and Administrative fee shall not apply to third-party royalty barrels. Buyer hereby agrees to use commercially reasonable efforts to obtain (i) the highest Sales Price for Crude Oil sold pursuant to this Agreement and (ii) the lowest out-of-pocket expenses incurred by Buyer to transport or exchange each Barrel of Crude Oil, in each case taking into account all circumstances surrounding the transportation and sale of the Crude Oil. Buyer will, upon request of Seller, provide information with respect to bids solicited by Buyer for the sale of Crude Oil. Notwithstanding this Section 2.4, the parties hereto affirm in all respects the Calumet Contract, including the price stated therein. 
        (a)   For Crude Oil that Buyer resells at a Delivery Point, the Sales Price shall be the price received by Buyer for each Barrel sold at the Delivery Point. 
        (b)   For Crude Oil that Buyer either (i) transports to, and resells at, a location other than a Delivery Point (a "Trade Location") or (ii) exchanges for other Crude Oil at a Trade Location, the Sales Price shall be determined as follows: 
        (x)   if such Crude Oil is not aggregated with other Crude Oil owned by Buyer, the Sales Price shall be equal to the price received by Buyer for each Barrel sold at the Trade Location; or 
        (y)   if such Crude Oil is aggregated with other Crude Oil owned by Buyer, the Sales Price shall be equal to the sum of (i) the posted price received by Buyer for each Barrel sold at the Trade Location and (ii) a premium equal to the Platt's P+ Average and plus or minus, as applicable, the Platt's Difference at the Trade Location. If the Platt's P+ Average or the 
4

Platt's Difference is not published, then the price shall be the weighted average for each Barrel of Buyer's sales at such Trade Location. 
        2.5   Payment. Payments by Buyer for Crude Oil purchased hereunder shall be based on the applicable Purchase Price, the volumes delivered by Sellers, and 100% of the interest shown on Exhibit A attached hereto, less state taxes which are withheld by Buyer. All payments shall be wired to Plains Resources for the account of the Sellers in accordance with written instructions from Plains Resources. Such wire transfers shall be made on the twentieth day of the month following the month of actual receipt of Crude Oil; provided that, if the twentieth day of the month falls on a Sunday or a banking holiday, payment will be made on the following Business Day, or if the twentieth day of the month falls on a Saturday, payment will be made on the preceding Business Day. 
        2.6   General Provisions. Plains Marketing, L.P.'s General Provisions dated November 1, 1998, are attached hereto as Exhibit C and are incorporated by reference and made a part of this Agreement. If any conflict should arise between the General Provisions and the information stated herein, this Agreement shall apply. 
        2.7   No Restrictions. No provision contained in this Agreement shall in any way be interpreted as being a restriction on the ability of any Seller to convey or transfer Crude Oil to any other Seller, or to any of their subsidiaries. However, all such Crude Oil conveyed or transferred to a Seller or subsidiary is and shall remain subject to this Agreement including the obligations contained in this Article II. 

ARTICLE III
RENEGOTIATION 
        3.1   Prior to November 23, 2006, and the end of each successive three-year period thereafter (an "Anniversary Date"), either the Sellers or Buyer may request, in writing, to renegotiate the Marketing and Administrative Fee. Any such renegotiation request must be accompanied with documentation supporting the request to either increase or decrease the Marketing and Administrative Fee, and shall be in accordance with the following procedures: 
        (a)   At least 120 days prior to the applicable Anniversary Date, either the Sellers or Buyer may request, in writing, to renegotiate the Marketing and Administrative Fee. If neither Sellers nor Buyer makes such a request, the Parties will be deemed to have agreed upon the then-existing Marketing and Administrative Fee. 
        (b)   Sellers and Buyer shall renegotiate the Marketing and Administrative Fee in good faith. If a revised Marketing and Administrative Fee has not been agreed upon at least 75 days prior to the applicable Anniversary Date, then Sellers may enter into negotiations for the sale of their Crude Oil with any Person who is not an Affiliate of Sellers. If Sellers do not reach an agreement with such non-affiliated Person at least 30 days prior to applicable Anniversary Date, then this Agreement shall continue and the Marketing and Administrative Fee shall be revised, effective the first day after the applicable Anniversary Date, to equal the Marketing and Administrative Fee last offered by Buyer. 
        (c)   If Sellers are successful in reaching agreement with such non-affiliated Person which provides for (i) a term of not less than one year nor more than three years; (ii) a Marketing and Administrative Fee which is less than the Marketing and Administrative Fee last offered by Buyer; and (iii) additional services substantially similar to those provided for in Article IV below, this Agreement shall terminate. Such termination shall be effective on the next Anniversary Date and, thereafter, Sellers may sell their Crude Oil to such non-affiliated Person during the term of their agreement with such Person. Within 120 days prior to the end of the term of such other agreement, either the Sellers or Buyer may request negotiations to resume this Agreement and to 
5

negotiate a revised Marketing and Administrative Fee in accordance with the procedures set forth above. 
        3.2   Sellers' and Buyer's right to request a renegotiation of the Marketing and Administrative Fee in order to resume this Agreement shall continue until such time that this Agreement terminates pursuant to Article V, or until such time that Sellers have sold their Crude Oil production to a Person who is not an Affiliate of Sellers for a period of five (5) consecutive years. 

ARTICLE IV
ADDITIONAL SERVICES 
        4.1   Additional Services. Upon request, Buyer agrees to provide Sellers with the following services, which shall be provided at no additional cost to Sellers except for reimbursement of all reasonable out-of-pocket costs incurred by Buyer to provide such services: 
        (a)   Provide Sellers with (i) historical information related to crude oil and natural gas prices in the possession of, or accessible to, Buyer, and (ii) Buyer's assessment of crude oil and natural gas prices to assist Sellers in their hedging strategies and decisions. 
        (b)   Execute hedges on behalf of, or for the benefit of, Sellers' crude oil and natural gas production. 
        (c)   Assist Sellers in their evaluation of potential acquisitions of oil and gas properties. 
        (d)   Assist Sellers in preparing information relating to their potential disposition of any of their crude oil and natural gas properties. 
        (e)   Market the production of their natural gas and natural gas liquids produced in association with Sellers' crude oil production. 
        (f)    Negotiate natural gas purchase agreements required for the operation of Sellers' properties. 
        (g)   Provide royalty distribution services. 
        4.2   Sellers Indemnity. Sellers agree to release, protect, defend, indemnify and hold Buyer, the General Partner, and their parents, subsidiaries, Affiliates, successors and assigns, and their agents, officers, directors, employees, representatives and contractors (hereinafter collectively referred to as the "Buyer Group") harmless from and against all claims, losses, costs, demands, damages, suits, judgments, penalties, liabilities, debts, expenses and causes of action of whatsoever nature or character, including but not limited to reasonable attorney's fees and other costs and expenses, which in any way arise out of or are related to this Agreement, including, without limitation, (i) the performance or subject matter of this Agreement, (ii) the performance of the services in Section 4.1, (iii) the breach by Sellers of any terms of this Agreement, or (iv) the ingress, egress or presence on any premises, whether land, buildings, or otherwise, in conjunction with this Agreement (collectively, the "Claims"), including claims due to personal injury, death, or loss or damage of property, whether or not caused by the sole, joint and/or concurrent negligence, fault or strict liability of any member of the Buyer Group, but in no event does this indemnity include claims caused by the Buyer Group's own gross negligence or willful misconduct. 

ARTICLE V
TERM 
        The term of this Agreement shall commence on the date of this Agreement and shall continue until November 23, 2009 unless sooner terminated as provided herein. This Agreement shall terminate (i) on the date on which no Affiliate of Plains Resources owns, directly or indirectly, an interest in the 
6

general partner of the MLP and (ii) at the election of Plains Resources upon a "Change of Control" of Plains Resources. A Change of Control of Plains Resources shall be deemed to have occurred upon the occurrence of one or more of the following events: (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Plains Entities to any Person and its Affiliates unless immediately following such sale, lease, exchange or other transfer such assets are owned, directly or indirectly, by the Plains Entities; (ii) the consolidation or merger of Plains Resources with or into another Person pursuant to a transaction in which the outstanding Voting Stock of Plains Resources is changed into or exchanged for cash, securities or other property, other than any such transaction where (a) the outstanding Voting Stock of Plains Resources is changed into or exchanged for Voting Stock of the surviving corporation or its parent and (b) the holders of the Voting Stock of Plains Resources immediately prior to such transaction own, directly or indirectly, not less than a majority of the Voting Stock of the surviving corporation or its parent immediately after such transaction; and (iii) a "person" or "group" (within the meaning of Sections 13(d) or 14(d)(2) of the Exchange Act) being or becoming the "beneficial owner" (as defined in Rules 13d-3 and 13d-5 under the Exchange Act) of more than 50% of all Voting Stock of Plains Resources, then outstanding, except in a merger or consolidation which would not constitute a Change of Control under clause (ii) above. Notwithstanding any of the foregoing, the anticipated merger of an Affiliate of Vulcan Energy Corporation with Plains Resources will not constitute a Change of Control hereunder, and the survivor of such merger shall remain a party hereto with all rights and obligations hereunder. 

ARTICLE VI
REPRESENTATIONS AND WARRANTIES 
        6.1   Representations and Warranties of Sellers. Each Seller represents and warrants to Buyer as of the date hereof that: 
        (a)   Each Seller is a corporation or limited partnership duly organized, validly existing, and in good standing under the laws of the state of their respective formation, and has all requisite corporate or partnership power and authority to execute, deliver, and perform this Agreement. 
        (b)   The execution, delivery, and performance by each Seller of this Agreement, and the consummation of the transactions contemplated herein, are within its corporate or partnership power and authority and have been duly authorized by all necessary corporate or partnership action. 
        (c)   No authorization, consent, or approval of, or other action by, or notice to, or filing with, any governmental authority, regulatory body, or any other Person is required for the due authorization, execution, delivery, or performance by any Seller of this Agreement, or the consummation of the transactions contemplated herein, except those authorizations, consents, and approvals that have been obtained and remain in full force and effect, and those notices and filings which have been made and remain in full force and effect. 
        (d)   This Agreement has been duly executed and delivered by each Seller, and is the legal, valid, and binding obligation of each Seller enforceable against it in accordance with its terms, except that enforceability may be subject to applicable bankruptcy, insolvency, reorganization, moratorium, or other similar laws affecting the rights of creditors generally, and by general equitable principles (whether enforcement is sought by proceedings in equity or at law). 
        (e)   Neither the execution, delivery, or performance by any Seller of this Agreement, nor the consummation of the transactions contemplated herein, will violate any provision of any Seller's Corporate Governance Documents, or any agreement, indenture, or instrument to which any Seller is a party or by which any of its property or assets are bound, or any provision of any existing Governmental Requirement. 
7

        6.2   Representations and Warranties of Buyer. Buyer represents and warrants to Sellers as of the date hereof that: 
        (a)   Buyer is a limited partnership duly organized, validly existing, and in good standing under the laws of the state of Texas, and has all requisite power and authority to execute, deliver, and perform this Agreement. 
        (b)   The execution, delivery, and performance by Buyer of this Agreement, and the consummation of the transactions contemplated herein, are within Buyer's partnership power and authority and have been duly authorized by all necessary partnership action. 
        (c)   No authorization, consent, or approval of, or other action by, or notice to, or filing with, any governmental authority, regulatory body, or any other Person is required for the due authorization, execution, delivery, or performance by Buyer of this Agreement, or the consummation of the transactions contemplated by this Agreement, except those authorizations, consents, and approvals that have been obtained and remain in full force and effect, and those notices and filings which have been made and remain in full force and effect. 
        (d)   This Agreement has been duly executed and delivered by Buyer, and is the legal, valid, and binding obligation of Buyer enforceable against Buyer in accordance with its terms, except that enforceability may be subject to applicable bankruptcy, insolvency, reorganization, moratorium, or other similar laws affecting the rights of creditors generally, and by general equitable principles (whether enforcement is sought by proceedings in equity or at law). 
        (e)   Neither the execution, delivery, or performance by Buyer of this Agreement, nor the consummation of the transactions contemplated hereby, will violate any provision of Buyer's Corporate Governance Documents, or any agreement, indenture, or instrument to which Buyer is a party or by which any of its property or assets are bound, or any provision of any existing Governmental Requirement. 

ARTICLE VII
CREDIT REQUIREMENTS 
        Purchases made by Buyer hereunder shall be on open account provided that: 
        (a)   Buyer or its Affiliates are not in default in the payment when due of any of its indebtedness in excess of $10,000,000 in the aggregate; and 
        (b)   Buyer's sales of Crude Oil hereunder are in accordance with the credit policies set forth by the General Partner's chief financial officer. 

ARTICLE VIII
SPECIFIED EVENTS 
        8.1   Buyer Specified Events. Each of the following shall constitute a Buyer Specified Event for all purposes of this Agreement: 
        (a)   Any amount due hereunder for the purchase of Crude Oil shall not be paid in full when due and Buyer does not cause the cure of such failure on or before the fifteenth (15th) Business Day after notice from a Seller of such failure is received by Buyer; 
        (b)   Buyer fails to receive and purchase Crude Oil production dedicated to this Agreement for reasons other than Force Majeure or any action or inaction of a Seller, and such failure is not remedied on or before the earlier of the thirtieth (30th) day after (i) any officer of the General Partner becomes aware of such failure or (ii) a Seller has given written notice of such failure to Buyer; 
8

        (c)   any representation and warranty made in Section 6.2 shall prove to have been incorrect in any material respect when made, and (i) such default or breach shall continue unremedied for a period of thirty (30) days after the earlier of (x) any officer of the General Partner becomes aware of such default or (y) a Seller has given written notice of such default to Buyer, and (ii) a Seller reasonably determines that the continuation of such default or breach may materially and adversely affect Buyer's ability to satisfy its obligations hereunder; 
        (d)   Buyer fails to negotiate in good faith as provided in Article III; 
        (e)   Buyer (i) is dissolved (other than pursuant to a consolidation, amalgamation or merger); (ii) becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due; (iii) makes a general assignment, arrangement or composition with or for the benefit of its creditors; (iv) institutes or has instituted against it a proceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar law affecting creditors' rights, or a petition is presented for its winding-up or liquidation, and, in the case of any such proceeding or petition instituted or presented against it, such proceeding or petition (A) results in a judgment or insolvency or bankruptcy or the entry of an order for relief or the making of an order for its winding-up or liquidation or (B) is not dismissed, discharged, stayed or restrained in each case within thirty (30) days of the institution or presentation thereof, (v) has a resolution passed for its winding-up or liquidation (other than pursuant to a consolidation, amalgamation or merger); (vi) seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official for it, or for all or substantially all its assets; (vii) has a secured party take possession of all or substantially all of its assets or has an execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or substantially all of its assets and such secured party maintains possession or any such process is not dismissed, discharged, stayed or restrained in each case within thirty (30) days thereafter; (viii) causes or is subject to any event with respect to it which, under the applicable laws of any jurisdiction, has an analogous effect to any of the events specified in clauses (i) to (vii) (inclusive); or (ix) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the foregoing acts. 
        8.2   Seller Specified Events. Each of the following shall constitute a Seller Specified Event for all purposes of this Agreement: 
        (a)   A Seller shall fail to deliver Crude Oil production subject to this Agreement and such failure is not remedied by such Seller on or before the fifteenth (15th) Business Day after notice from Buyer of such failure is received by the Seller; 
        (b)   Any representation and warranty made in Section 6.1 shall prove to have been incorrect in any material respect when made, and (i) such default or breach shall continue unremedied for a period of thirty (30) days after the earlier of (x) any officer of a Seller becomes aware of such default or (y) Buyer has given written notice of such default to a Seller, and (ii) Buyer reasonably determines that the continuation of such default or breach may materially adversely affect Seller's ability to satisfy its obligations hereunder; 
        (c)   A Seller (i) is dissolved (other than pursuant to a consolidation, amalgamation or merger); (ii) becomes insolvent or is unable to pay its debts or fails or admits in writing its inability generally to pay its debts as they become due; (iii) makes a general assignment, arrangement or composition with or for the benefit of its creditors; (iv) institutes or has instituted against it a proceeding seeking a judgment of insolvency or bankruptcy or any other relief under any bankruptcy or insolvency law or other similar law affecting creditors' rights, or a petition is presented for its winding-up or liquidation, and, in the case of any such proceeding or petition instituted or presented against it, such proceeding or petition (A) results in a judgment or 
9

insolvency or bankruptcy or the entry of an order for relief or the making of an order for its winding-up or liquidation or (B) is not dismissed, discharged, stayed or restrained in each case within thirty (30) days of the institution or presentation thereof, (v) has a resolution passed for its winding-up or liquidation (other than pursuant to a consolidation, amalgamation or merger); (vi) seeks or becomes subject to the appointment of an administrator, provisional liquidator, conservator, receiver, trustee, custodian or other similar official for it or for all or substantially all its assets; (vii) has a secured party take possession of all or substantially all of its assets or has an execution, attachment, sequestration or other legal process levied, enforced or sued on or against all or substantially all its assets and such secured party maintains possession, or any such process is not dismissed, discharged, stayed or restrained, in each case within thirty (30) days thereafter; (viii) causes or is subject to any event with respect to it which, under the applicable laws of any jurisdiction, had an analogous effect to any of the events specified in clauses (i) to (vii) (inclusive); or (ix) takes any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any of the foregoing acts; 
        (d)   A Seller or Sellers fail to negotiate in good faith as provided in Article III. 
        8.3   Early Termination. If any Specified Event shall have occurred and be continuing, then the Non-defaulting Party may by notice to the Defaulting Party designate a date (which date shall not be earlier than 60 days after receipt of such notice) on which this Agreement shall terminate as between the Non-defaulting Party and the Defaulting Party, and this Agreement shall terminate as between the Non-defaulting Party and the Defaulting Party on such designated date whether or not such Specified Event is then continuing; provided that the provisions of Section 8.4 shall survive such termination. 
        8.4   Specified Damages. The Defaulting Party shall pay all damages and expenses incurred by the Non-defaulting Party as a result of the termination of this Agreement under Section 8.3 arising out of or in connection with any collection, bankruptcy, insolvency, or other enforcement proceedings resulting from the occurrence of the Specified Event giving rise to such termination. Payment of such damages and expenses shall be the Defaulting Party's only liability, and the Non-defaulting Party's sole remedy and exclusive claim, as a result of the Specified Event and the resulting termination of this Agreement under Section 8.3 as between the Non-defaulting Party and the Defaulting Party. 

ARTICLE IX
FORCE MAJEURE 
        9.1   Excuse for Nonperformance. Subject to the other provisions of this Agreement, the obligations of a Party under this Agreement (including the obligation of Sellers to deliver Crude Oil), except the obligation to pay money to the other Party, may be suspended for a reasonable period as a result of an event of Force Majeure, to the extent that nonperformance is caused by Force Majeure, and the affected Party shall be relieved of liability for failing to perform from the inception of such event and during the continuance thereof and the time of any such suspension of obligations shall be added to the term of this Agreement. 
        9.2   Definition. An event of "Force Majeure" means war, riots, insurrections, fire, explosions, sabotage, strikes, and other labor or industrial disturbances, acts of God or the elements, Governmental Requirements, disruption or breakdown of production or transportation facilities, delays of pipeline carrier in receiving and delivering crude oil tendered, or any other cause, whether similar or not, reasonably beyond the control of the affected Party. 
        9.3   Notice and Cure. A Party affected by Force Majeure shall, as a condition to invoking Force Majeure as an excuse for nonperformance under this Agreement, promptly give notice of the occurrence of Force Majeure to the other Party, with reasonably detailed information about the event of Force Majeure and the effect it has had, and is anticipated to have, on the performance of the invoking Party, and shall confirm such notice of Force Majeure and its consequences in writing no later 
10

than two (2) Business Days after the occurrence of such event of Force Majeure. The invoking Party shall exercise due diligence in good faith to remedy the Force Majeure and resume full performance under this Agreement as soon as reasonably practicable. 

ARTICLE X
GENERAL PROVISIONS 
        10.1 No Survival of Representations and Warranties. Notwithstanding anything to the contrary herein, all representations and warranties provided by Sellers and Buyer in Article VI shall not survive the termination of this Agreement. 
        10.2 Headings. The headings, captions, and arrangements contained in this Agreement have been inserted for convenience only and shall not be deemed in any manner to modify, explain, enlarge, or restrict any of the provisions hereof. 
        10.3 Rights and Remedies Cumulative. Except as provided in Section 8.4, the rights and remedies of each of the Parties under this Agreement shall be cumulative and non-exclusive of any other rights or remedies which each Party may have under any other agreement or instrument, by operation of law, or otherwise. 
        10.4 Entire Agreement; Supersedure. This Agreement constitutes the entire agreement of the parties relating to the matters contained herein, superseding all prior contracts or agreements, whether oral or written, relating to the matters contained herein. 
        10.5 Severability. If any provision of this Agreement or the application thereof to any Person or circumstance shall be held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law. 
        10.6 Choice of Law; Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the State of Texas, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each party hereby submits to the jurisdiction of the state and federal courts in the State of Texas and to venue in Houston, Harris County, Texas. 
        10.7 Binding Agreement; No Third Party Beneficiaries. This Agreement is entered into for the benefit of the Parties and their permitted successors and assigns. It shall be binding upon and shall inure to the benefit of such Parties and their successors and assigns. There are no other beneficiaries of this Agreement. 
        10.8 No Agency. Except as otherwise provided in this Agreement, nothing herein shall serve to create any agency, employment, master and servant relationship, partnership, or joint venture between Sellers and Buyer, their Affiliates, or any officer, director, employee or agent thereof. 
        10.9 Notice. All notices or requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing same in the United States mail, addressed to the Person to be notified, postpaid, and registered or certified with return receipt requested or by delivering such notice in person or by telecopier or telegram to such party. Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by telegram or telecopier shall be effective upon actual receipt if received during the recipient's normal business hours, or at the beginning of the recipient's next business day after receipt if not received during the recipient's normal business hours. All notices to be sent to a party pursuant to this Agreement shall be 
11

sent to or made at the address set forth below, or at such other address as such party may stipulate to the other parties in the manner provided in this Section 10.9. 
 	 	If to Buyer:	 	If to Sellers:	

 	
Plains Marketing, L.P.
333 Clay St., Suite 1600
Houston, Texas 77002
Attention: Harry N. Pefanis	
 	
Plains Resources Inc.
700 Milam, Suite 3100
Houston, Texas 77002
Attention: President	
        10.10 Effect of Waiver or Consent. No waiver or consent, express or implied, by any party to or of any breach or default by any Person in the performance by such Person of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such party of its rights hereunder until the applicable statute of limitations period has run. 
        10.11 Assignment. No party shall have the right to assign its rights or obligations under this Agreement without the consent of the other parties hereto. 
        10.12 Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatory parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument. 
        10.13 Amendment or Modification. This Agreement may be amended or modified from time to time only by the written agreement of all the parties hereto. Each such instrument shall be reduced to writing and shall be designated on its face an "Amendment" or an "Addendum" to this Agreement. 
        10.14 Further Assurances. In connection with this Agreement and all transactions contemplated by this Agreement, each signatory party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement and all such transactions. 
        10.15 Withholding or Granting of Consent. Each party may, with respect to any consent or approval that it is entitled to grant pursuant to this Agreement, grant or withhold such consent or approval in its sole and uncontrolled discretion, with or without cause, and subject to such conditions as it shall deem appropriate. 
        10.16 U.S. Currency. All sums and amounts payable to or to be payable pursuant to the provisions of this Agreement shall be payable in coin or currency of the United States of America that, at the time of payment, is legal tender for the payment of public and private debts in the United States of America. 
        10.17 Laws and Regulations. Notwithstanding any provision of this Agreement to the contrary, no party hereto shall be required to take any act, or fail to take any act, under this Agreement if the effect thereof would be to cause such party to be in violation of any applicable law, statute, rule or regulation. 
        10.18 Construction of Agreement. In construing this Agreement: 
        (a)   no consideration shall be given to the fact or presumption that one Party had a greater or lesser hand in drafting this Agreement; 
        (b)   examples shall not be construed to limit, expressly or by implication, the matter they illustrate; 
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        (c)   the word "includes" and its derivatives means "includes, but is not limited to" and corresponding derivative expressions; 
        (d)   a defined term has its defined meaning throughout this Agreement, regardless of whether it appears before or after the place where it is defined; 
        (e)   the plural shall be deemed to include the singular, and vice versa; 
        (f)    each gender shall be deemed to include the other genders; 
        (g)   each reference to an article, section, or subsection refers to an article, section, or subsection of this Agreement unless expressly otherwise provided; and 
        (h)   all references to a party shall include all successors and permitted assigns of such party. 
[The next page is the signature page] 
13

        IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date and year first above written. 
 	 	BUYER:	

 	
PLAINS MARKETING, L.P.
By: Plains Marketing GP Inc.,
          its General Partner	

 	
By:	
/s/  HARRY N. PEFANIS      
	
 	 	 	Name: Harry N. Pefanis
Title: President and Chief Operating Officer	

 	
SELLERS:	

 	
PLAINS RESOURCES INC.	

 	
By:	
/s/  JOHN T. RAYMOND      
	
 	 	 	Name: John T. Raymond
Title:President and Chief Executive Officer	

 	
CALUMET FLORIDA INC.	

 	
By:	
/s/  JOHN T. RAYMOND      
	
 	 	 	Name: John T. Raymond
Title: President	
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EXHIBIT A 
Sellers' Crude Oil Producing Properties
Within Marketing Area 
Seller
	 	Field
	 	State
	 	Delivery Point
	
Calumet Florida LLC:	 	Racoon Point	 	Florida	 	Pipeline facilities nominated by Buyer at Nederland Texas	
 	 	Sunniland	 	Florida	 	(same)	
 	 	Bear Island	 	Florida	 	(same)	
 	 	South Bear Island	 	Florida	 	(same)	
 	 	Sunoco	 	Florida	 	(same)	
 	 	West Felda	 	Florida	 	(same)	

EXHIBIT B 
Existing Contracts 
[none] 

EXHIBIT B 
PLAINS MARKETING, L.P.
GENERAL PROVISIONS 
        SPECIFIC TERMS:    The General Provisions set forth herein are incorporated by reference and made a part of that certain Crude Oil Marketing Agreement dated July    , 2004, by and among Buyer and Sellers (the "Agreement"). In the event there is any inconsistency between these General Provisions and the Agreement, the Agreement shall prevail. All capitalized terms not otherwise defined in this Exhibit C shall have the meaning set forth for them in the Agreement. 
        WARRANTY/INDEMNIFICATION:    The Sellers warrant good title to or the right to sell all Crude Oil delivered pursuant to the Agreement and warrant that such shall be free from all royalties, liens, encumbrances, and all applicable foreign, federal, state and local taxes that are imposed upon the production and/or removal of Crude Oil from the premises through the Delivery Point. Sellers also warrant that such Crude Oil has been produced, handled and transported to the Delivery Point in accordance with all applicable laws, rules and regulations of all local, state and federal authorities. Sellers further warrant that all Crude Oil will be merchantable. Sellers further agree to indemnify, defend and hold harmless Buyer, the General Partner, and their parents, subsidiaries, Affiliates, successors and assigns, and their agents, officers, directors, employees, representatives and contractors from and against all loss, costs, damages or expenses of any nature by or on account of Buyer, the General Partner, or their parents, subsidiaries, Affiliates, successors and assigns, and their agents, officers, directors, employees, representatives or contractors having made (i) 100% payment to Sellers or (ii) payment to interest owners on behalf of Sellers based on information provided by Sellers. 
        TAXES:    Sellers shall be responsible for all production, severance and other related taxes incurred prior to delivery, provided that Buyer is hereby authorized to withhold such taxes from payments to Sellers and remit such taxes to the proper regulatory authority. Buyer shall be responsible for the payment of any and all taxes now in effect or hereafter imposed on the Crude Oil after the Delivery Point. 
        TITLE AND RISK OF LOSS:    Title to, possession of and risk of loss of Crude Oil shall pass to the Buyer as the Crude Oil passes from equipment owned or controlled by the Sellers, or owned or controlled by a party designated to make delivery on behalf of the Sellers, into equipment owned or controlled by Buyer, or owned or controlled by a party designated to take delivery on behalf of Buyer. Provided, however, that in cases of in line transfers, title to, possession of and risk of loss of Crude Oil shall pass to Buyer as the Crude Oil is deemed transferred. Such shall be deemed transferred to Buyer upon completion of each in line transfer with quantity determined, when available, in accordance with the transfer statement or other receipt issued by the carrier or storage facility. 
        EQUAL DELIVERIES:    For purposes of determining price, Crude Oil delivered during any given month hereunder shall be deemed to have been delivered in equal daily quantities during such month except as follows: Deliveries of Crude Oil at lease locations based on meter tickets shall be deemed to have been delivered in equal daily quantities during the period covered by the meter ticket and deliveries of Crude Oil at lease locations based on run tickets, shall be deemed to have been delivered on the date recorded on each run ticket issued by the designated carrier. 
        MEASUREMENTS AND TESTS:    All measurements hereunder shall represent one hundred percent (100%) volume with such volume and gravity adjusted to sixty degrees (60°) Fahrenheit temperature. Procedures for measuring and testing, except for deliveries through positive displacement-type liquid meters, shall be according to latest ASTM published methods then in effect. Procedures for such metered-type delivery shall be according to the latest ASME-API published methods then in effect. The Crude Oil delivered hereunder shall be merchantable and acceptable to the carriers involved and full deduction shall be made for all BS&W content according to the latest ASTM standard method then in effect. Any Party shall have the right to have a representative present to witness all gauges, tests and measurements; however, should any Party hereto fail to have a 

representative present during such measuring and testing, the measurements and tests of the other Party will be accepted. 
        CONFIRMATION OF DELIVERY:    Confirmation of delivery shall be based on run tickets evidencing such delivery or allocation statements issued by the carriers involved. 
        DIVISION ORDERS:    In the event any Party signs a division order in favor of the other Party pertaining to the object of the Agreement, terms of the Agreement shall supersede the terms of such division order to the extent that there may be a conflict between the two. 
        DISPUTE-WITHHOLDING OF FUNDS:    If a suit is filed that affects the interest of a Seller, written notice shall be given to Buyer by such Seller together with a copy of the complaint or petition filed. In the event of a claim or dispute that affects title to the division interest credited to such Seller, Buyer is authorized to withhold payments accruing to such interest, without interest unless otherwise required by applicable statute, until the claim of dispute is settled. 
        NOTICES:    Sellers agree to notify Buyer in writing of any change of Payee, including changes of interest contingent on payment of money or expiration of time. No change is binding on Buyer until the recorded copy of the instrument of change or documents satisfactorily evidencing such change are furnished to Buyer at the time the change occurs. Any change shall be made effective on the first day of the month following receipt of such notice by Buyer. 
        SET-OFF:    In the event any Party shall fail to make timely delivery of any Crude Oil, or other applicable products due and owing to the other Party, or in the event any Party shall fail to make timely payment of any monies due and owing to the other Party, the other Party may offset any deliveries or payments due under this or any other agreement between the parties. 
        AUDIT:    Any Party and their duly authorized representatives shall have access to the accounting records and other documents maintained by the other Party which relate to the Agreement, and shall have the right to audit such records at any reasonable time or times within twenty-four (24) months of the date a statement is rendered. 

QuickLinks
EXHIBIT 10.2
TABLE OF CONTENTS
CRUDE OIL MARKETING AGREEMENT
ARTICLE I DEFINITIONS
ARTICLE II PURCHASE AND SALE
ARTICLE III RENEGOTIATION
ARTICLE IV ADDITIONAL SERVICES
ARTICLE V TERM
ARTICLE VI REPRESENTATIONS AND WARRANTIES
ARTICLE VII CREDIT REQUIREMENTS
ARTICLE VIII SPECIFIED EVENTS
ARTICLE IX FORCE MAJEURE
ARTICLE X GENERAL PROVISIONS
EXHIBIT A
EXHIBIT B
EXHIBIT B

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EXHIBIT 10.3 

AMENDED AND RESTATED

OMNIBUS AGREEMENT

among

PLAINS RESOURCES INC.

PLAINS ALL AMERICAN PIPELINE, L.P.

PLAINS MARKETING, L.P.

PLAINS PIPELINE, L.P.

and

PLAINS ALL AMERICAN GP LLC 

TABLE OF CONTENTS 
ARTICLE I Definitions	 	1	
 	1.1 Definitions	 	1	

ARTICLE II Business Opportunities	
 	
2	
 	2.1 Restricted Businesses	 	2	
 	2.2 Permitted Exceptions	 	2	
 	2.3 Procedures	 	3	
 	2.4 Termination	 	4	
 	2.5 Scope of Restricted Business Prohibition	 	4	
 	2.6 Enforcement	 	4	

ARTICLE III Miscellaneous	
 	
5	
 	3.1 Choice of Law; Submission to Jurisdiction	 	5	
 	3.2 Notice	 	5	
 	3.3 Entire Agreement; Supersedure	 	5	
 	3.4 Effect of Waiver or Consent	 	5	
 	3.5 Amendment or Modification	 	5	
 	3.6 Assignment	 	5	
 	3.7 Counterparts	 	5	
 	3.8 Severability	 	5	
 	3.9 Gender, Parts, Articles and Sections	 	6	
 	3.10 Further Assurances	 	6	
 	3.11 Withholding or Granting of Consent	 	6	
 	3.12 U.S. Currency	 	6	
 	3.13 Laws and Regulations	 	6	
 	3.14 Negotiation of Rights of Limited Partners, Assignees, and Third Parties	 	6	
i

AMENDED AND RESTATED OMNIBUS AGREEMENT 
        THIS AMENDED AND RESTATED OMNIBUS AGREEMENT, dated as of July 23, 2004, among Plains Resources Inc., a Delaware corporation ("Plains Resources"), Plains All American Pipeline, L.P., a Delaware limited partnership (the "MLP"), Plains All American GP LLC, a Delaware corporation ("GP LLC"), Plains Marketing GP Inc., a Delaware corporation ("GP Inc."), Plains Marketing, L.P., a Texas limited partnership ("Operating OLP"), and Plains Pipeline, L.P., a Texas limited partnership ("Plains OLP" and, together with Operating OLP, the "OLPs") amends and restates that certain Omnibus Agreement dated as of November 23, 1998 among Plains Resources, Plains All American Inc., a Delaware corporation, the MLP and the predecessors to the OLPs. 
R E C I T A L S: 
        Plains Resources, the MLP, the OLPs and GP LLC, in its capacity as the general partner of the general partner of the MLP and GP Inc., in its capacity as the general partner of the OLPs, desire by their execution of this Agreement to evidence their understanding, as more fully set forth in Article II of this Agreement, with respect to (a) those business opportunities that Plains Resources will not avail itself of during the Applicable Period unless each of the MLP and the OLPs has declined to engage in such business opportunity for its own account and (b) the procedures whereby such business opportunities are to be offered to the MLP and the OLPs and accepted or declined. 
        In consideration of the premises and the covenants, conditions, and agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: 

ARTICLE I
Definitions 
        1.1   Definitions. 
        (a)   Capitalized terms used herein but not defined shall have the meanings given them in the MLP Agreement. 
        (b)   As used in this Agreement, the following terms shall have the respective meanings set forth below: 
        "Affiliate" shall mean, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term "control" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise. For clarity, Plains Exploration & Production Company and Plains Resources are not Affiliates of each other for purposes of this Agreement. 
        "Agreement" shall mean this Amended and Restated Omnibus Agreement, as it may be amended, modified, or supplemented from time to time. 
        "Applicable Period" shall mean the period commencing on November 23, 1998 and terminating on the date on which no Plains Entity owns, directly or indirectly, an interest in the general partner of the MLP. 
        "Conflicts Committee" shall have the meaning attributed to such term in the MLP Agreement. 
        "General Partner" shall mean GP LLC and its successors as general partner of the general partner the MLP, unless the context otherwise requires. 
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        "LLC Agreement" shall mean the Amended and Restated Limited Liability Company Agreement dated as of June 8, 2001, as amended September 16, 2003 and as may be amended from time to time. 
        "Marketing Agreement" shall mean that Amended and Restated Crude Oil Marketing Agreement dated as of the date hereof among Plains Resources, Calumet Florida LLC and Operating OLP. 
        "MLP Agreement" shall mean the Third Amended and Restated Agreement of Limited Partnership of the MLP, dated as of June 27, 2001, as amended on April 15, 2004, and as such agreement may be amended from time to time, to which reference is hereby made for all purposes of this Agreement. 
        "Non-Affiliate Purchaser" shall have the meaning attributed to such term in Section 2.3. 
        "Offer" shall have the meaning attributed to such term in Section 2.3. 
        "Partnership Entities" shall mean the General Partner, the MLP, the OLPs and any Affiliate controlled by the General Partner, the MLP or the OLPs. 
        "Partnership Group" shall mean the MLP, the OLPs and any subsidiary of any such entities. 
        "Person" shall mean an individual, corporation, partnership, joint venture, trust, limited liability company, unincorporated organization or any other entity. 
        "Plains Entities" shall mean Plains Resources and any of its Affiliates, other than the Partnership Entities. 
        "Restricted Business" shall have the meaning attributed to such term in Section 2.1. 
        "Second Offer" shall have the meaning attributed to such term in Section 2.3. 

ARTICLE II
Business Opportunities 
        2.1   Restricted Businesses. During the Applicable Period, each of the Plains Entities shall be prohibited from engaging in or acquiring any business engaged in the following activities (a "Restricted Business"): (a) crude oil storage, terminalling and gathering activities in any state in the United States (except for Hawaii), the Outer Continental Shelf of the United States or any province or territory in Canada, for any Person other than a Plains Entity or Partnership Entity, (b) crude oil marketing activities, and (c) transportation of crude oil by pipeline in any state in the United States (except for Hawaii), the Outer Continental Shelf of the United States or any province or territory in Canada, for any Person other than a Plains Entity. A Restricted Business shall not include any activities required to be performed by a Plains Entity as the operator pursuant to any operating agreement entered into by such Plains Entity with respect to oil and gas properties owned jointly with other Persons. 
        2.2   Permitted Exceptions. Notwithstanding any provision of Section 2.1 to the contrary, a Plains Entity may engage in a Restricted Business under the following circumstances: 
        (a)   The Restricted Business was engaged in by the Plains Entity on November 23, 1998. 
        (b)   The Restricted Business is conducted pursuant to and in accordance with the terms of the Marketing Agreement or any other arrangement entered into with the MLP or either of the OLPs with the concurrence of the Conflicts Committee. 
        (c)   The value of the assets acquired in a transaction that comprise a Restricted Business does not exceed $10 million, as determined by the Board of Directors of Plains Resources. 
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        (d)   (i) The value of the assets acquired in a transaction that comprise a Restricted Business exceed $10 million, as determined by the Board of Directors of Plains Resources and (ii) the General Partner (with the approval of the Conflicts Committee) has elected not to cause a member of the Partnership Group to pursue such opportunity in accordance with the procedures set forth in Section 2.3. 
        2.3   Procedures. In the event that a Plains Entity acquires a Restricted Business comprised of assets valued in excess of $10 million, as determined by the Board of Directors of Plains Resources, then not later than 30 days after the consummation of the acquisition by such Plains Entity of the Restricted Business, such Plains Entity shall notify the General Partner of such purchase and offer the Partnership the opportunity to purchase such Restricted Business. As soon as practicable, but in any event, within 30 days after receipt of such notification, the General Partner shall notify the Plains Entity that either (i) the General Partner has elected, with the approval of the Conflicts Committee, not to cause a member of the Partnership Group to purchase such Restricted Business, in which event the Plains Entity shall be free to continue to engage in such Restricted Business, or (ii) the General Partner has elected to cause a member of the Partnership Group to purchase such Restricted Business, in which event the following procedures shall be followed: 
        (a)   The Plains Entity shall submit a good faith offer to the General Partner to sell the Restricted Business (the "Offer") to any member of the Partnership Group on the terms and for the consideration stated in the Offer. 
        (b)   The Plains Entity and the General Partner shall negotiate in good faith, for 60 days after receipt of such Offer by the General Partner, the terms on which the Restricted Business will be sold to a member of the Partnership Group. The Plains Entity shall provide all information concerning the business, operations and finances of such Restricted Business as may be reasonably requested by the General Partner. 
        (i)    If the Plains Entity and the General Partner agree on such terms within 60 days after receipt by the General Partner of the Offer, a member of the Partnership Group shall purchase the Restricted Business on such terms as soon as commercially practicable after such agreement has been reached. 
        (ii)   If the Plains Entity and the General Partner are unable to agree on the terms of a sale during such 60-day period, the Plains Entity shall attempt to sell the Restricted Business to a Person that is not an Affiliate of the Plains Entity (a "Non-Affiliate Purchaser") within nine months of the termination of such 60-day period. Any such sale to a Non-Affiliate Purchaser must be for a purchase price, as determined by the Board of Directors of Plains Resources, not less than 95% of the purchase price last offered by a member of the Partnership Group. 
        (c)   If, after the expiration of such nine-month period, the Plains Entity has not sold the Restricted Business to a Non-Affiliate Purchaser, it shall submit another Offer (the "Second Offer") to the General Partner within seven days after the expiration of such nine-month period. The Plains Entity shall provide all information concerning the business, operations and finances of such Restricted Business as may be reasonably requested by the General Partner. 
        (i)    If the General Partner, with the concurrence of the Conflicts Committee, elects not to cause a member of the Partnership Group to pursue the Second Offer, the Plains Entity shall be free to continue to engage in such Restricted Business. 
        (ii)   If the General Partner shall elect to cause a member of the Partnership Group to purchase such Restricted Business, then the General Partner and the Plains Entity shall negotiate the terms of such purchase for 60 days. If the Plains Entity and the General Partner agree on such terms within 60 days after receipt by the General Partner of the Second Offer, 
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a member of the Partnership Group shall purchase the Restricted Business on such terms as soon as commercially practicable after such agreement has been reached. 
        (iii)  If during such 60-day period, no agreement has been reached between the Plains Entity and the General Partner or a member of the Partnership, the Plains Entity and the General Partner will engage an independent investment banking firm with a national reputation to determine the value of the Restricted Business. Such investment banking firm will determine the value of the Restricted Business within 30 days and furnish the Plains Entity and the General Partner its opinion of such value. The Plains Entity will pay the fees and expenses of such investment banking firm. Upon receipt of such opinion, the General Partner will have the option, subject to the approval of the Conflicts Committee, to (A) cause a member of the Partnership Group to purchase the Restricted Business for an amount equal to the value determined by such investment banking firm or (B) decline to purchase such Restricted Business, in which event the Plains Entity will be free to continue to engage in such Restricted Business. 
        2.4   Termination. The provisions of this Article II may be terminated by Plains Resources upon a "Change of Control" of Plains Resources. A Change of Control of Plains Resources shall be deemed to have occurred upon the occurrence of one or more of the following events: (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Plains Entities to any Person and its Affiliates unless immediately following such sale, lease, exchange or other transfer such assets are owned, directly or indirectly, by the Plains Entities; (ii) the consolidation or merger of Plains Resources with or into another Person pursuant to a transaction in which the outstanding Voting Stock of Plains Resources is changed into or exchanged for cash, securities or other property, other than any such transaction where (a) the outstanding Voting Stock of Plains Resources is changed into or exchanged for Voting Stock of the surviving corporation or its parent and (b) the holders of the Voting Stock of Plains Resources immediately prior to such transaction own, directly or indirectly, not less than a majority of the Voting Stock of the surviving corporation or its parent immediately after such transaction; and (iii) a "person" or "group" (within the meaning of Sections 13(d) or 14(d)(2) of the Exchange Act) being or becoming the "beneficial owner" (as defined in Rules 13d-3 and 13d-5 under the Exchange Act) of more than 50% of all Voting Stock of Plains Resources, then outstanding, except in a merger or consolidation which would not constitute a Change of Control under clause (ii) above. Notwithstanding any of the foregoing, the anticipated merger of an Affiliate of Vulcan Energy Corporation with Plains Resources will not constitute a Change of Control hereunder, and the survivor of such merger shall remain a party hereto with all rights and obligations hereunder. 
        2.5   Scope of Restricted Business Prohibition. Except as restricted by this Article II (or by other agreement, including without limitation the LLC Agreement and the Partnership Agreement), each Plains Entity shall be free to engage in any business activity whatsoever, including those that may be in direct competition with any Partnership Entity. For clarity, any owner of equity interests in Plains Resources may make passive investments in the MLP's competitors; provided, however, that no such owner (nor any Plains Entity) shall directly or indirectly use any knowledge or confidential information it received through the ownership by a Plains Entity of a member interest in the General Partner or representation on the Board of Directors of the General Partner to compete, or to engage in or become interested financially in any person that competes, in a Restricted Business. 
        2.6   Enforcement. The Plains Entities agree and acknowledge that the Partnership Group does not have an adequate remedy at law for the breach by the Plains Entities of the covenants and agreements set forth in this Article II, and that any breach by the Plains Entities of the covenants and agreements set forth in Article II would result in irreparable injury to the Partnership Group. The Plains Entities further agree and acknowledge that any member of the Partnership Group may, in addition to the 
4

other remedies which may be available to the Partnership Group, file a suit in equity to enjoin the Plains Entities from such breach, and consent to the issuance of injunctive relief hereunder. 

ARTICLE III
Miscellaneous 
        3.1   Choice of Law; Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the State of Texas, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each party hereby submits to the jurisdiction of the state and federal courts in the State of Texas and to venue in Houston, Harris County, Texas. 
        3.2   Notice. All notices or requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing same in the United States mail, addressed to the Person to be notified, postpaid, and registered or certified with return receipt requested or by delivering such notice in person or by telecopier or telegram to such party. Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by telegram or telecopier shall be effective upon actual receipt if received during the recipient's normal business hours, or at the beginning of the recipient's next business day after receipt if not received during the recipient's normal business hours. All notices to be sent to a party pursuant to this Agreement shall be sent to or made at the address set forth below such party's signature to this Agreement, or at such other address as such party may stipulate to the other parties in the manner provided in this Section 3.2. 
        3.3   Entire Agreement; Supersedure. This Agreement constitutes the entire agreement of the parties relating to the matters contained herein, superseding all prior contracts or agreements, whether oral or written, relating to the matters contained herein. 
        3.4   Effect of Waiver or Consent. No waiver or consent, express or implied, by any party to or of any breach or default by any Person in the performance by such Person of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such party of its rights hereunder until the applicable statute of limitations period has run. 
        3.5   Amendment or Modification. This Agreement may be amended or modified from time to time only by the written agreement of all the parties hereto; provided, however, that the MLP and the OLPs may not, without the prior approval of the Conflicts Committee, agree to any amendment or modification of this Agreement that, in the reasonable discretion of the General Partner, will adversely affect the holders of Common Units. Each such instrument shall be reduced to writing and shall be designated on its face an "Amendment" or an "Addendum" to this Agreement. 
        3.6   Assignment. No party shall have the right to assign its rights or obligations under this Agreement without the consent of the other parties hereto. 
        3.7   Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatory parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument. 
        3.8   Severability. If any provision of this Agreement or the application thereof to any Person or circumstance shall be held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law. 
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        3.9   Gender, Parts, Articles and Sections. Whenever the context requires, the gender of all words used in this Agreement shall include the masculine, feminine and neuter, and the number of all words shall include the singular and plural. All references to Article numbers and Section numbers refer to Parts, Articles and Sections of this Agreement. 
        3.10 Further Assurances. In connection with this Agreement and all transactions contemplated by this Agreement, each signatory party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement and all such transactions. 
        3.11 Withholding or Granting of Consent. Each party may, with respect to any consent or approval that it is entitled to grant pursuant to this Agreement, grant or withhold such consent or approval in its sole and uncontrolled discretion, with or without cause, and subject to such conditions as it shall deem appropriate. 
        3.12 U.S. Currency. All sums and amounts payable to or to be payable pursuant to the provisions of this Agreement shall be payable in coin or currency of the United States of America that, at the time of payment, is legal tender for the payment of public and private debts in the United States of America. 
        3.13 Laws and Regulations. Notwithstanding any provision of this Agreement to the contrary, no party hereto shall be required to take any act, or fail to take any act, under this Agreement if the effect thereof would be to cause such party to be in violation of any applicable law, statute, rule or regulation. 
        3.14 Negotiation of Rights of Limited Partners, Assignees, and Third Parties. The provisions of this Agreement are enforceable solely by the parties to this Agreement, and no Limited Partner, Assignee or other Person shall have the right, separate and apart from the MLP or the OLP, to enforce any provision of this Agreement or to compel any party to this Agreement to comply with the terms of this Agreement. 
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        IN WITNESS WHEREOF, the parties have executed this Agreement on, and effective as of, the date first written above. 
 	 	PLAINS RESOURCES INC.	

 	
By:	
 	
/s/  JOHN T. RAYMOND      

Name: John T. Raymond
Title: President and Chief Executive Officer	

 	
Address for Notice:	

 	
700 Milam, Suite 3100
Houston, Texas 77002
Telecopy Number: (713) 654-1523	

 	
PLAINS ALL AMERICAN PIPELINE, L.P.	

 	
By: PLAINS AAP, L.P., its general partner	

 	
By: PLAINS ALL AMERICAN GP LLC, its general partner	

 	

By:	
/s/  HARRY N. PEFANIS      

Name: Harry N. Pefanis
Title: President	

 	
Address for Notice:	
 	 	333 Clay Street, Suite 1600
Houston, Texas 77002
Telecopy Number: (713) 646-4313	

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 	 	PLAINS MARKETING, L.P.	

 	
By: PLAINS MARKETING GP INC., its general partner	

 	

By:	
/s/  HARRY N. PEFANIS      

Name: Harry N. Pefanis
Title: President and Chief Operating Officer	

 	
Address for Notice:	

 	
333 Clay Street, Suite 1600
Houston, Texas 77002
Telecopy Number: (713) 646-4313	

 	
PLAINS PIPELINE, L.P.	

 	
By: PLAINS MARKETING GP INC., its general partner	

 	

By:	
/s/  HARRY N. PEFANIS      

Name: Harry N. Pefanis
Title: President and Chief Operating Officer	

 	
Address for Notice:	

 	
333 Clay Street, Suite 1600
Houston, Texas 77002
Telecopy Number: (713) 646-4313	

 	
PLAINS ALL AMERICAN GP LLC	

 	
By:	
 	
/s/  HARRY N. PEFANIS      

Name: Harry N. Pefanis
Title: President and Chief Operating Officer	

 	
Address for Notice:	

 	
333 Clay Street, Suite 1600
Houston, Texas 77002
Telecopy Number: (713) 646-4313	
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EXHIBIT 10.3
TABLE OF CONTENTS
AMENDED AND RESTATED OMNIBUS AGREEMENT
ARTICLE I Definitions
ARTICLE II Business Opportunities
ARTICLE III Miscellaneous

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EXHIBIT 10.4 
SECOND AMENDMENT TO CREDIT AGREEMENT 
        THIS SECOND AMENDMENT TO CREDIT AGREEMENT (this "Amendment") dated as of the 20th day of April 2004, by and among PLAINS MARKETING, L.P. ("Borrower"), FLEET NATIONAL BANK, as Administrative Agent, and the Lenders party hereto. 
W I T N E S S E T H: 
        WHEREAS, Borrower, Administrative Agent and Lenders named therein entered into that certain Credit Agreement dated as of November 21, 2003, as amended by that certain First Amendment to Credit Agreement dated as of December 19, 2003 (as heretofore amended, the "Original Agreement") for the purposes and consideration therein expressed; and 
        WHEREAS, Borrower, Administrative Agent and Lenders desire to amend the Original Agreement for the purposes described herein; 
        NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows: 
ARTICLE I.—Definitions and References
        § 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment. 
        § 1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this § 1.2. 
        "Amendment" means this Second Amendment to Credit Agreement. 
        "Credit Agreement" means the Original Agreement as amended hereby. 
ARTICLE II.—Amendments
        § 2.1. Special Financing Requests. Section 2.1 of the Original Agreement is hereby amended by adding a new subsection (f) at the end thereof, to read as follows: 
        (f)    Special Financing Requests. During the Request Period, Borrower may from time to time submit to Lenders special financing requests (a "Special Financing Request") substantially in the form of a Financing Request-Initial and otherwise acceptable to Lenders, except that such Special Financing Request shall (i) specify volumes of Petroleum Products that would otherwise qualify as Hedged Eligible Inventory, except that such Petroleum Products have been previously purchased or are scheduled for purchase prior to the following month, and (ii) request Lenders to make pro rata advances on such date following delivery of such Petroleum Products as Borrower may specify with a repayment date as specified in such Special Financing Request, but in no event more than six months after the specified funding date, to fund the purchase of such Petroleum Products. For purposes of the foregoing: (A) the Hedged Value and Sale Value of such Petroleum Products shall be calculated as though such Petroleum Products qualify as Hedged Eligible Inventory and such Special Financing Request constitutes a Financing Request-Initial, and (B) such Petroleum Products shall be deemed to be "Financed Hedged Eligible Inventory" hereunder. Any such Special Financing Request may be evaluated by Lenders and shall be processed as set forth in Section 2.1(b) as though such Special Financing Request constituted a Financing Request-Initial. With respect to any such Special Financing Request, if one or more Participating Lenders shall in 
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their sole and absolute discretion commit to finance such purchase of such Petroleum Products, on the specified funding date each Participating Lender shall, subject to the netting provisions set forth in Section 2.1(d), make its Loan pursuant to Section 2.2, as though such Special Financing Request constitutes a Financing Request-Final; provided, notwithstanding Section 2.8(c) hereof, such Loans shall constitute Term Loans due and payable on the repayment date specified in such Special Financing Request. Borrower hereby agrees that in the event any Loan made pursuant to a Special Financing Request shall not be repaid on the next following Settlement Date, Borrower shall furnish to Lenders a monthly updated Special Financing Request with respect to such original Special Financing Request, updating the information described therein. The Collateral specified in any such Special Financing Request (and any related updated Special Financing Request) shall primarily secure such Loans made with respect to such Collateral, and secondarily secure all other Obligations. 
        § 2.2. Link Asset Financings. Borrower desires to submit to Lenders monthly financing requests of up to $60,000,000 per month with respect to in transit Hedged Eligible Inventory relating to Borrower's recent acquisition of certain assets of Link Energy LLC, to be delivered to Borrower commencing May 2004 through and including August 2004, (a "Link Asset Financing Request") substantially in the form of a Financing Request-Initial, except that such Link Asset Financing Request shall not include a schedule specifying the Approved Locations through which such Hedged Eligible Inventory will be in transit, but shall include a schedule listing sales contracts constituting Eligible Receivables with an aggregate face amount not less than $67,000,000 and shall provide for the granting of a lien on and security interest therein. Any such Link Asset Financing Request shall be evaluated by Lenders and shall be processed as set forth in Section 2.1(b), (c) and (d) as though such Link Asset Financing Request constitutes a Financing Request-Initial. The Collateral specified in any such Link Asset Financing Request shall primarily secure such Letters of Credit issued with respect thereto and Borrower's reimbursement obligations with respect thereto, as well as Loans made with respect to such Collateral, and secondarily secure all other Obligations. 
ARTICLE III.—Conditions of Effectiveness
        § 3.1. Effective Date. This Amendment shall become effective as of the date first written above, when and only when 
        (i)    Administrative Agent shall have received, at Administrative Agent's office a counterpart of this Amendment executed and delivered by Borrower and Lenders; 
        (ii)   Administrative Agent shall have additionally received all of the following documents, each document (unless otherwise indicated) being dated the date of receipt thereof by Administrative Agent, duly authorized, executed and delivered, and in form and substance satisfactory to Administrative Agent: 
        Supporting Documents. Such supporting documents as Administrative Agent may reasonably request. 
ARTICLE IV.—Representations and Warranties
        § 4.1. Representations and Warranties of Borrower. In order to induce Administrative Agent and Lenders to enter into this Amendment, Borrower represents and warrants to Administrative Agent and each Lender that: 
        (a)   The representations and warranties contained in Article V of the Original Agreement are true and correct at and as of the time of the effectiveness hereof, except to the extent that such representation and warranty was made as of a specific date. 
        (b)   Borrower is duly authorized to execute and deliver this Amendment, to the extent a party thereto, and Borrower is and will continue to be duly authorized to borrow and perform its 
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obligations under the Credit Agreement. Borrower has duly taken all action necessary to authorize the execution and delivery of this Amendment and to authorize the performance of its obligations hereunder. 
        (c)   The execution and delivery by Borrower of this Amendment, the performance by it of its obligations hereunder, and the consummation of the transactions contemplated hereby, do not and will not conflict with any provision of any Law or of the organizational documents of Borrower, or of any material agreement, judgment, license, order or permit applicable to or binding upon Borrower, or result in the creation of any Lien upon any assets or properties of Borrower, except in favor of Administrative Agent and other Permitted Liens. Except for those which have been duly obtained, no consent, approval, authorization or order of any Tribunal or third party is required in connection with the execution and delivery by Borrower of this Amendment or to consummate the transactions contemplated hereby. 
        (d)   When duly executed and delivered, this Amendment and each of the Loan Documents, as amended hereby, will be a legal and binding instrument and agreement of Borrower, enforceable in accordance with its terms, (subject, as to enforcement of remedies, to applicable bankruptcy, insolvency and similar laws applicable to creditors' rights generally). 
ARTICLE V.—Miscellaneous
        § 5.1. Ratification of Agreements. The Original Agreement, as hereby amended, is hereby ratified and confirmed in all respects. The Loan Documents, as they may be amended or affected by this Amendment, are hereby ratified and confirmed in all respects by Borrower. Any reference to the Credit Agreement in any Loan Document shall be deemed to refer to this Amendment also. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Administrative Agent or any Lender under the Credit Agreement or any other Loan Document nor constitute a waiver of any provision of the Credit Agreement or any other Loan Document. 
        § 5.2. Ratification of Security Documents. Borrower, Administrative Agent, and Lenders each acknowledge and agree that any and all indebtedness, liabilities or obligations, arising under or in connection with the LC Obligations or the Notes, are Obligations and are secured indebtedness under, are guarantied by, and are secured by, each and every Security Document. Borrower hereby re-pledges, re-grants and re-assigns a security interest in and lien on every asset of Borrower described as Collateral in any Security Document. 
        § 5.3. Survival of Agreements. All representations, warranties, covenants and agreements of Borrower shall survive the execution and delivery of this Amendment and the performance hereof, including without limitation the making or granting of each Loan, and shall further survive until all of the Obligations under the Credit Agreement are paid in full. All statements and agreements contained in any certificate or instrument delivered by Borrower hereunder or under the Credit Agreement to Administrative Agent or any Lender shall be deemed to constitute representations and warranties by, or agreements and covenants of, Borrower under this Amendment and under the Credit Agreement. 
        § 5.4. Loan Documents. This Amendment is a Loan Document, and all provisions in the Credit Agreement pertaining to Loan Documents apply hereto. 
        § 5.5. GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND ANY APPLICABLE LAWS OF THE UNITED STATES OF AMERICA IN ALL RESPECTS, INCLUDING CONSTRUCTION, VALIDITY AND PERFORMANCE.
        § 5.6. Counterparts. This Amendment may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment. Delivery of an executed signature page by facsimile transmission shall be effective as delivery of a manual executed counterpart. 
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        IN WITNESS WHEREOF, this Amendment is executed as of the date first above written. 
BORROWER:	 	PLAINS MARKETING, L.P.	

 	
By: Plains Marketing GP Inc., General Partner	

 	
By:	
/s/  AL SWANSON      

Al Swanson, Vice President and Treasurer	

LENDER PARTIES:	
 	
FLEET NATIONAL BANK,
Administrative Agent, LC Issuer and Lender	

 	
By:	
/s/  TERRENCE RONAN      

Terrence Ronan, Managing Director	

 	
BNP PARIBAS, Lender	

 	
By:	
/s/  JORDAN N      

Name: Jordan N
Title: Vice President	

 	
By:	
/s/  A-C MATHIOT      

Name: A-C Mathiot
Title: Managing Director	

 	
FORTIS CAPITAL CORP., Lender	

 	
By:	
/s/  CHAD CLARK      

Name: Chad Clark
Title: Vice President	

 	
By:	
/s/  LEONARD RUSSO      

Name: Leonard Russo
Title: Director	

 	
SOCIETE GENERALE, Lender	

 	
By:	
/s/  EMMANUEL CHESNEAU      

Name: Emmanuel Chesneau
Title: Director	

 	
By:	
/s/  BARBARA PAULSEN      

Name: Barbara Paulsen
Title: Director	
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EXHIBIT 10.4
SECOND AMENDMENT TO CREDIT AGREEMENT

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Exhibit 18.1 
August 6, 2004 
Board of Directors
Plains All American GP LLC, the general partner of
Plains AAP, L.P., the general partner of
Plains All American Pipeline, L.P.
333 Clay Street, Suite 1600
Houston, Texas 77002-4101 
Dear Directors: 
        We are providing this letter to you for inclusion as an exhibit to Plains All American Pipeline, L.P.'s ("PAA") Form 10-Q filing pursuant to Item 601 of Regulation S-K. 
        We have been provided a copy of PAA's Quarterly Report on Form 10-Q for the period ended June 30, 2004. Note 1 therein describes a change in accounting principle from recording pipeline linefill held in pipelines not owned by PAA ("linefill in third party assets") as a separate asset to including linefill in third party assets in operating inventory. It should be understood that the preferability of one acceptable method of accounting over another for linefill in third party assets has not been addressed in any authoritative accounting literature, and in expressing our concurrence below we have relied on management's determination that this change in accounting principle is preferable. Based on our reading of management's stated reasons and justification for this change in accounting principle in the Form 10-Q, and our discussions with management as to their judgment about the relevant business planning factors relating to the change, we concur with management that such change represents, in PAA's circumstances, the adoption of a preferable accounting principle in conformity with Accounting Principles Board Opinion No. 20. 
        We have not audited any financial statements of PAA as of any date or for any period subsequent to December 31, 2003. Accordingly, our comments are subject to change upon completion of an audit of the consolidated financial statements covering the period of the accounting change. 
Very truly yours, 
PricewaterhouseCoopers LLP 

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Exhibit 18.1

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EXHIBIT 31.1 
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 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 report; 
3.
Based on my knowledge, the financial statements, and other financial information included in this 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 report; 
4.
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: 
a)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; 
(b)
[intentionally omitted pursuant to SEC Release No. 34-47986]; 
(c)
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end the period covered by this report based on such evaluation; and 
(d)
disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): 
(a)
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and 
(b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. 
Date: August 6, 2004 
/s/ Greg L. Armstrong

Greg L. Armstrong
Chief Executive Officer	 	 	 	

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EXHIBIT 31.1

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EXHIBIT 31.2 
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 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 report; 
3.
Based on my knowledge, the financial statements, and other financial information included in this 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 report; 
4.
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: 
a)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; 
b)
[intentionally omitted pursuant to SEC Release No. 34-47986]; 
(c)
evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end the period covered by this report based on such evaluation; and 
(d)
disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 
5.
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): 
(a)
all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and 
(b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. 
Date: August 6, 2004 
/s/ Phil Kramer

Phil Kramer
Chief Financial Officer	 	 	 	

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EXHIBIT 31.2

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EXHIBIT 32.1 
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 June 30, 2004 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 condition and results of operations of the Company. 

 	
/s/  GREG L. ARMSTRONG      

Name: Greg L. Armstrong
Date: August 6, 2004	

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EXHIBIT 32.1

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EXHIBIT 32.2 
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 June 30, 2004 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 condition and results of operations of the Company. 

 	
/s/  PHIL KRAMER      

Name: Phil Kramer
Date: August 6, 2004	

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EXHIBIT 32.2