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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

ý	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 ý    No o

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý    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

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PART I. FINANCIAL INFORMATION

Item 1. CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

		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.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

		Three Months Ended 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.

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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.

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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

11

$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.

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        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

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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

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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.

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        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.

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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.

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        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.

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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.

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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.

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        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;

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•

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.

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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

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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.

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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.

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SIGNATURES

        Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.

	PLAINS ALL AMERICAN PIPELINE, L.P.
	By:	PLAINS AAP, L.P., its general partner
	By:	PLAINS ALL AMERICAN GP LLC, its general partner
Date: 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)

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