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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 September 30, 2003
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 November 1, 2003, there were outstanding 44,135,939 Common Units, 1,307,190 Class B Common Units and 10,029,619 Subordinated Units.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
Item 1. CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets:
	September 30, 2003, and December 31, 2002	3
Consolidated Statements of Operations:
	For the three months and nine months ended September 30, 2003 and 2002	4
Consolidated Statements of Cash Flows:
	For the nine months ended September 30, 2003 and 2002	5
Consolidated Statement of Partners' Capital:
	For the nine months ended September 30, 2003	6
Consolidated Statements of Comprehensive Income:
	For the three months and nine months ended September 30, 2003 and 2002	7
Consolidated Statement of Changes in Accumulated Other Comprehensive Income:
	For the nine months ended September 30, 2003	7
Notes to the Consolidated Financial Statements		8
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		22
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS		48
Item 4. CONTROLS AND PROCEDURES		48
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		49
Item 2. Changes in Securities and Use of Proceeds		49
Item 3. Defaults Upon Senior Securities		49
Item 4. Submission of Matters to a Vote of Security Holders		49
Item 5. Other Information		49
Item 6. Exhibits and Reports on Form 8-K		50
Signatures		51

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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)

		September 30, 2003			December 31, 2002
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	3,418		$	3,501
Trade accounts receivable, net			350,916			499,909
Inventory			162,202			81,849
Other current assets			47,692			17,676
	Total current assets		564,228			602,935
PROPERTY AND EQUIPMENT			1,181,944			1,030,303
Accumulated depreciation			(109,873	)		(77,550	)
			1,072,071			952,753
OTHER ASSETS
Pipeline linefill			109,481			62,558
Other, net			64,362			48,329
	Total assets	$	1,810,142		$	1,666,575
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	524,866		$	488,922
Due to related parties			24,182			23,301
Short-term debt			35,141			99,249
Other current liabilities			45,342			25,777
	Total current liabilities		629,531			637,249
LONG-TERM LIABILITIES
Long-term debt under credit facilities, including current maturities of $8,000 and $9,000, respectively			254,100			310,126
Senior notes, net of unamortized discount of $360 and $390, respectively			199,640			199,610
Other long-term liabilities and deferred credits			21,483			7,980
	Total liabilities		1,104,754			1,154,965
COMMITMENTS AND CONTINGENCIES (NOTE 9)
PARTNERS' CAPITAL
Common unitholders (44,135,939 and 38,240,939 units outstanding at September 30, 2003, and December 31, 2002, respectively)			704,387			524,428
Class B common unitholder (1,307,190 units outstanding at each date)			19,171			18,463
Subordinated unitholders (10,029,619 units outstanding at each date)			(41,676	)		(47,103	)
General partner			23,506			15,822
	Total partners' capital		705,388			511,610
		$	1,810,142		$	1,666,575

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

		Three Months Ended September 30,						Nine Months Ended September 30,
		2003			2002			2003			2002
		(unaudited)
REVENUES		$	3,053,677		$	2,344,089		$	9,044,774		$	5,874,759
COST OF SALES AND OPERATIONS (excluding depreciation and LTIP accrual)			3,001,627			2,299,823			8,879,867			5,750,398
LTIP Accrual—operations (Note 7)			1,390			—			1,390			—
	Gross margin (excluding depreciation)		50,660			44,266			163,517			124,361
EXPENSES
General and administrative (excluding LTIP accrual)			12,198			11,512			37,431			33,389
LTIP Accrual—general and administrative (Note 7)			6,006			—			6,006			—
Depreciation and amortization-operations			10,510			7,730			29,491			19,713
Depreciation and amortization-general and administrative			1,478			1,251			4,673			3,412
	Total expenses		30,192			20,493			77,601			56,514
OPERATING INCOME			20,468			23,773			85,916			67,847
OTHER INCOME/(EXPENSE)
Interest expense (net of $165 and $182, respectively, capitalized for the three month periods and $461 and $640, respectively, capitalized for the nine month periods)			(8,794	)		(7,368	)		(26,480	)		(20,175	)
Interest income and other, net			197			(88	)		184			(123	)
NET INCOME		$	11,871		$	16,317		$	59,620		$	47,549
NET INCOME-LIMITED PARTNERS		$	10,392		$	15,159		$	54,958		$	44,515
NET INCOME-GENERAL PARTNER		$	1,479		$	1,158		$	4,662		$	3,034
BASIC NET INCOME PER LIMITED PARTNER UNIT		$	0.20		$	0.33		$	1.06		$	1.01
DILUTED NET INCOME PER LIMITED PARTNER UNIT		$	0.19		$	0.33		$	1.05		$	1.01
BASIC WEIGHTED AVERAGE UNITS OUTSTANDING			52,788			46,027			51,735			44,188
DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING			53,435			46,027			52,407			44,188

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)

			Nine Months Ended September 30,
			2003			2002
			(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income			$	59,620		$	47,549
Adjustments to reconcile to cash flows from operating activities:
	Depreciation and amortization			34,164			23,125
	Change in derivative fair value			1,731			2,130
	Non-cash portion of LTIP accrual (Note 7)			3,700			—
Changes in assets and liabilities, net of acquisitions:
	Accounts receivable and other			131,758			(129,930	)
	Inventory			(84,690	)		104,664
	Pipeline linefill			(40,449	)		—
	Accounts payable and other current liabilities			84,717			67,954
	Settlement of environmental indemnities			4,600			—
	Due to related parties			500			11,895
		Net cash provided by operating activities		195,651			127,387
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions (Note 2)				(99,897	)		(323,786	)
Additions to property and equipment				(52,180	)		(27,445	)
Proceeds from sales of assets				7,076			1,390
Other investing activities				232			—
		Net cash used in investing activities		(144,769	)		(349,841	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net repayments on long-term revolving credit facility				(13,122	)		(42,313	)
Net borrowings (repayments) on short-term letter of credit and hedged inventory facility				(67,315	)		752
Principal payments on senior secured term loan				(43,000	)		(3,000	)
Cash paid in connection with financing arrangements				(87	)		(5,396	)
Net proceeds from the issuance of common units (Note 6)				161,905			145,346
Proceeds from the issuance of senior unsecured notes				—			199,600
Distributions paid to unitholders and general partner				(89,346	)		(71,642	)
		Net cash provided by (used in) financing activities		(50,965	)		223,347
Effect of translation adjustment on cash				—			(98	)
Net increase (decrease) in cash and cash equivalents				(83	)		795
Cash and cash equivalents, beginning of period				3,501			3,511
Cash and cash equivalents, end of period			$	3,418		$	4,306
Cash paid for interest, net of amounts capitalized			$	24,286		$	23,476

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

5

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL

(in thousands)

	Common Unitholders				Class B Common Unitholder				Subordinated Unitholders
																Total Partners' Capital Amount
													General Partner Amount
	Units	Amounts			Units	Amounts			Units	Amounts
	(unaudited)
Balance at December 31, 2002	38,241	$	524,428		1,307	$	18,463		10,030	$	(47,103	)	$	15,822		$	511,610
Issuance of common units	5,895		158,516		—		—		—		—			3,389			161,905
Distributions	—		(65,527	)	—		(2,141	)	—		(16,423	)		(5,255	)		(89,346	)
Other comprehensive income	—		44,168		—		1,446		—		11,097			4,888			61,599
Net income	—		42,802		—		1,403		—		10,753			4,662			59,620
Balance at September 30, 2003	44,136	$	704,387		1,307	$	19,171		10,030	$	(41,676	)	$	23,506		$	705,388

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(in thousands)

Statements of Comprehensive Income

	Three Months Ended September 30,					Nine Months Ended September 30,
	2003		2002			2003		2002
	(unaudited)
Net income	$	11,871	$	16,317		$	59,620	$	47,549
Other comprehensive income (loss)		25,286		(16,723	)		61,599		(5,775	)
Comprehensive income (loss)	$	37,157	$	(406	)	$	121,219	$	41,774

Statement of Changes in Accumulated Other Comprehensive Income

			Net Deferred Gain (Loss) on Derivative Instruments			Currency Translation Adjustments			Total
			(unaudited)
Balance at December 31, 2002			$	(8,207	)	$	(6,219	)	$	(14,426	)
	Current period activity
		Reclassification adjustments for settled contracts		(6,570	)		—			(6,570	)
		Changes in fair value of outstanding hedge positions		32,784			—			32,784
		Currency translation adjustment		—			35,385			35,385
	Total period activity			26,214			35,385			61,599
Balance at September 30, 2003			$	18,007		$	29,166		$	47,173

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") formed in 1998, and is engaged in interstate and intrastate marketing, transportation and terminalling of crude oil and liquified petroleum gas ("LPG"). Our operations are conducted directly and indirectly through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana and the Canadian provinces of Alberta and Saskatchewan.

        The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of September 30, 2003, and December 31, 2002, (ii) the results of our consolidated operations for the three months and nine months ended September 30, 2003 and 2002, (iii) our consolidated cash flows for the nine months ended September 30, 2003 and 2002, (iv) our consolidated changes in partners' capital for the nine months ended September 30, 2003, (v) our consolidated comprehensive income for the three months and nine months ended September 30, 2003 and 2002, and (vi) our changes in consolidated accumulated other comprehensive income for the nine months ended September 30, 2003. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior period amounts to conform to current period presentation. The results of operations for the three months and nine months ended September 30, 2003 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2002 Annual Report on Form 10-K.

Note 2—Acquisitions and Dispositions

        The following acquisitions made in 2003, and accounted for under Statement of Financial Accounting Standards ("SFAS") No. 141 "Business Combinations", did not have a material effect on either our financial position, results of operations or cash flows, either individually or in the aggregate. Thus, no pro forma financial information or additional disclosures otherwise required under SFAS 141 are included herein. The cash portion of these acquisitions was funded from cash on hand and borrowings under our revolving credit facility.

ArkLaTex Pipeline System

        In September 2003, we made a deposit (approximately $17.0 million) to acquire the ArkLaTex Pipeline System from Link Energy (formerly EOTT Energy). The ArkLaTex Pipeline System consists of 240 miles of active crude oil gathering and mainline pipelines and connects to our Red River Pipeline System near Sabine, Texas. Also included in the transaction were 470,000 barrels of active crude oil storage capacity, the assignment of certain of Link Energy's crude oil supply contracts and crude oil linefill and working inventory comprised of approximately 108,000 barrels. The total purchase price of approximately $21.3 million is comprised of a) $14.0 million of cash paid to Link Energy for the pipeline system, b) $2.9 million of cash paid to Link Energy to purchase crude oil linefill and working inventory, c) $3.6 million for transaction costs and estimated near-term capital costs and d) $0.8 million associated with the satisfaction of outstanding claims for accounts receivable and inventory balances.

8

The near-term capital costs are associated with modifications required to enhance the capacity and validate and improve the integrity of the pipeline (which are expected to extend the life and improve the usefulness of the pipeline system) and enable us to operate it in conformity with our policies and specifications and are expected to be incurred within the next year. A portion of the purchase price has been allocated to the crude oil supply contracts; however, we are in the process of evaluating certain estimates made in the purchase price allocation. Thus, the allocation is subject to refinements. The acquisition closed and was effective on October 1, 2003, and will be included in our Pipeline Operations and our Gathering, Marketing, Terminalling and Storage segments, as appropriate.

Other Acquisitions

        During the first half of 2003, we made six acquisitions from various entities for an aggregate purchase price of $85.7 million. 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 $3.0 million that was allocated to investment in affiliates and $0.5 million that was allocated to goodwill and other intangible assets, the remaining aggregate purchase price was allocated to property and equipment.

Shutdown of Rancho Pipeline System

        We acquired the Rancho Pipeline System in conjunction with the acquisition of several other West Texas assets from Shell Pipeline Company, LP and Equilon Enterprises, LLC in August of 2002. The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, terminated in March 2003. Upon termination, the agreement required the owners to take the pipeline system, in which we owned an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not accept nominations for movements after February 28, 2003. This shutdown was contemplated at the time of the acquisition and was accounted for under purchase accounting in accordance with SFAS No. 141 "Business Combinations." The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. In June 2003, we completed transactions whereby we transferred all of our ownership interest in approximately 240 miles of the total 458 miles of the pipeline in exchange for $4 million and approximately 500,000 barrels of crude oil tankage in West Texas. We are currently in discussions for the remainder of the pipe to be salvaged or sold. No gain or loss has been recorded on the shutdown of the Rancho System or these transactions.

Note 3—Trade Accounts Receivable

        Trade accounts receivable included in the consolidated balance sheets are reflected net of our allowance for doubtful accounts. We routinely review our receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such delays involve billing delays and discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy.

        At September 30, 2003 approximately 99% of our net trade accounts receivable classified as current were less than 60 days past the scheduled invoice date. Our allowance for doubtful accounts receivable classified as current totaled $3.2 million, representing 41% of trade receivable balances

9

greater than 60 days past the scheduled invoice date. At September 30, 2003, our allowance for doubtful accounts receivable classified as long-term totaled $5.0 million, representing 100% of all long-term receivable balances.

Note 4—Debt

        At September 30, 2003 our total debt balance was approximately $488.9 million (including approximately $35.2 million of short-term debt) with a fair value of approximately $509.2 million. The carrying amounts of the variable rate instruments in our credit facilities approximate fair value primarily because the interest rates fluctuate with prevailing market rates, while the interest rate on the 7.75% senior notes is fixed and the fair value is based on quoted market prices. Total availability under our long-term revolving credit facilities was approximately $441.9 million (net of $8.0 million to refinance term loan maturities due in the next twelve months). This reflects the use of proceeds from the September 2003 sale of common units (see Note 6) to reduce net borrowings under our revolving credit facilities at September 30, 2003, to approximately $0.1 million and the prepayment of approximately $34 million on our Senior secured term B loan. The payment on the Senior secured term B loan was made in anticipation of our potential refinancing.

        At September 30, 2003, we have classified $8.0 million of term loan maturities due in the next twelve months as long-term due to our intent and ability to refinance those maturities using the revolving credit facilities. The following table reflects the aggregate maturities of our long-term debt for the next five years (in millions):

Calendar Year		Payment
2004		$	8.0
2005			8.1
2006			76.0
2007			162.0
2008			—
Thereafter			200.0
	Total(1)	$	454.1

(1)

Includes unamortized discount on 7.75% senior notes of approximately $0.4 million.

Note 5—Earnings Per Common Unit

        The following table sets forth the computation of basic and diluted earnings per limited partner unit (in thousands, except for per unit amounts). The net income available to limited partners and the

10

weighted average limited partner units outstanding have been adjusted for the impact of the contingent equity issuance related to the CANPET acquisition (see Note 9).

			Three Months Ended September 30,					Nine Months Ended September 30,
			2003			2002		2003			2002
Numerator:
	Numerator for basic earnings per limited partner unit:
		Net income available for common unitholders	$	10,392		$	15,159	$	54,958		$	44,515
	Effect of dilutive securities:
		Increase in general partner's incentive distribution—Contingent equity issuance		(16	)		—		(46	)		—
	Numerator for diluted earnings per limited partner unit		$	10,376		$	15,159	$	54,912		$	44,515
Denominator:
	Denominator for basic earnings per limited partner unit:
		Weighted average number of limited partner units		52,788			46,027		51,735			44,188
	Effect of dilutive securities:
		Contingent equity issuance		647			—		672			—
	Denominator for diluted earnings per limited partner unit:
		Weighted average number of limited partner units		53,435			46,027		52,407			44,188
Basic net income per limited partner unit			$	0.20		$	0.33	$	1.06		$	1.01
Diluted net income per limited partner unit			$	0.19		$	0.33	$	1.05		$	1.01

Note 6—Partners' Capital and Distributions

Distributions

        On October 23, 2003, we declared a cash distribution of $0.55 per unit on our outstanding common units, Class B common units and subordinated units. The distribution is payable on November 14, 2003, to unitholders of record on November 4, 2003, for the period July 1, 2003, through September 30, 2003. The total distribution to be paid is approximately $32.5 million, with approximately $25.0 million to be paid to our common unitholders, $5.5 million to be paid to our subordinated unitholders and $0.6 million and $1.4 million to be paid to our general partner for its general partner and incentive distribution interests, respectively. The distribution is in excess of the minimum quarterly distribution specified in the partnership agreement.

        During the previous months of 2003, we declared three separate cash distributions on our outstanding common units, Class B common units and subordinated units. The total distributions paid were approximately $89.3 million, with approximately $67.6 million paid to our common unitholders, $16.4 million paid to our subordinated unitholders and $1.8 million and $3.5 million paid to our general partner for its general partner and incentive distribution interests, respectively. The

11

distributions each were in excess of the minimum quarterly distribution specified in the partnership agreement.

Equity Offerings

        In September 2003, we completed a public offering of 3,250,000 common units for $30.91 per unit. The offering resulted in gross proceeds of approximately $100.5 million from the sale of the units and approximately $2.1 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $4.5 million. Net proceeds of approximately $98.0 million were used to reduce outstanding borrowings under the domestic revolving credit facility and reduce the principal balance on our Senior secured term B loan.

        In March 2003, we completed a public offering of 2,645,000 common units for $24.80 per unit. The offering resulted in gross proceeds of approximately $65.6 million from the sale of the units and approximately $1.3 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $3.0 million. Net proceeds of approximately $63.9 million were used to reduce outstanding borrowings under the domestic revolving credit facility.

Subordinated Unit Conversion

        The subordination period (as defined in the partnership agreement) for the 10,029,619 outstanding subordinated units will end if certain financial tests are met for three consecutive, non-overlapping four-quarter periods (the "testing period"). During the first quarter after the end of the subordination period, all of the subordinated units will convert into common units, and will participate pro rata with all other common units in future distributions. Early conversion of a portion of the subordinated units may occur if the testing period is satisfied before December 31, 2003. We are now in the testing period and, in connection with the payment of the quarterly distribution in November 2003, 25% of the subordinated units will convert to common units. If we continue to meet the testing period requirements, the remaining subordinated units will convert in the first quarter of 2004.

Note 7—Vesting of Unit Grants Under Long-Term Incentive Plan

        As of September 30, 2003, there were grants covering approximately one million restricted units outstanding under our Long-Term Incentive Plan ("LTIP"). Restricted unit grants become eligible to vest in the same proportion as the conversion of our outstanding subordinated units into common units, subject to any additional vesting requirements.

        As discussed in Note 6, 25% of the outstanding subordinated units will convert into common units in connection with the payment of the quarterly distribution in November 2003. In conjunction with this conversion, approximately 35,000 restricted units will vest, and a 90-day period will commence for approximately 220,000 additional restricted units that will not have any remaining vesting requirements except that the holder must continue employment with the Partnership for the remainder of the 90-day period.

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Probable Vesting

        Under generally accepted accounting principles, we are required to recognize an expense when it is considered probable that the financial tests for conversion of subordinated units and required distribution levels will be met and that the restricted unit grants will vest. At September 30, 2003 we concluded that the vesting of approximately 255,000 restricted units was probable and thus accrued approximately $7.4 million of compensation expense based upon an estimated market price of $30.05 per unit (the unit price as of September 30, 2003), our share of employment taxes and other related costs. Under the LTIP, we may satisfy our obligations using a combination of cash, the issuance of new units and delivery of units purchased in the open market. We anticipate that in November 2003, to satisfy the vesting of those restricted units that vest substantially contemporaneously with the conversion of subordinated units, we will issue approximately 18,000 common units after netting for taxes and paying cash in lieu of a portion of the vested units. For those restricted units that require passage of time to vest, the 90-day period will expire and final vesting will occur in February 2004. We estimate we will issue approximately 100,000 common units in the first quarter of 2004 in connection with this probable vesting.

Potential Vesting

        At the current distribution level of $2.20 per unit, assuming that the additional subordination conversion tests are met as of December 31, 2003, approximately 580,000 additional units will vest in connection with the payment of the quarterly distribution in February 2004. If at December 31, 2003 it is considered probable that this distribution level and tests will be met, the costs associated with the vesting of these additional units will be estimated and accrued in the fourth quarter of 2003. At a distribution level of $2.30 to $2.49, the number of additional units that would vest would increase by approximately 87,000. At a distribution level at or above $2.50, the number of additional units that would vest would increase by approximately 87,000. In all cases, vesting is subject to any applicable continuing employment requirements.

        Subject to providing those holding less than a certain number of restricted units the option to receive cash, we are currently planning to issue units to satisfy the majority of restricted unit obligations that vest in connection with the conversion of subordinated units. If all conditions to vesting are met, we currently project the issuance of units (approximately 100,000 common units in connection with the probable vesting and approximately 239,000 common units in connection with the potential vesting) in the first half of 2004 to satisfy such obligations. Obligations satisfied by the issuance of units will result in a non-cash compensation expense. Purchase of units would result in a cash charge to compensation expense. In addition, the "company match" portion of payroll taxes, plus the value of any units withheld for taxes, will result in a cash charge. The aggregate amount of the potential charge to expense will be determined by the unit price on the date vesting occurs multiplied by the number of units, plus our share of associated employment taxes. The amount of the potential charge is subject to various factors, including the unit price on the date vesting occurs, and thus is not known at this time. As mentioned above, we have accrued approximately $7.4 million as of September 30, 2003 in connection with the probable vesting. At the current distribution level and based on an assumed market price of $30.05 per unit (the unit price as of September 30, 2003), the aggregate additional charge that would be triggered by the potential vesting (that is, if we determine it is probable that the additional units will vest) would be approximately $21 million, of which approximately $17 million would be accrued as of December 31, 2003 (although payment and issuance of units would not occur until the first and second quarters of 2004).

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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 September 30, 2003, balance sheet includes assets of $40.8 million ($37.5 million current), liabilities of $23.5 million ($6.9 million current) and related unrealized net gains deferred to Other Comprehensive Income ("OCI") of $18.0 million. Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet. In addition, revenues for the nine months ended September 30, 2003, included a noncash loss of $1.7 million ($0.7 million noncash loss before the reversal of the prior period fair value adjustment related to contracts that settled during the current period) resulting from (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items.

        The total amount of deferred net gains or 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 nine months ended September 30, 2003 and 2002, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Of the $18.0 million net gain deferred to OCI at September 30, 2003, a gain of $28.8 million will be reclassified to earnings in the next twelve months and the remaining loss by March 2014. Since these amounts are based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

        The following sections discuss our risk management activities in the indicated categories.

Commodity Price Risk Hedging

        We hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments utilized consist primarily of futures and option contracts traded on the New York Mercantile Exchange and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies. In accordance with SFAS No. 133 "Accounting for Derivative

14

Instruments and Hedging Activities," these derivative instruments are recognized in the balance sheet or earnings at their fair values. The majority of our commodity price risk derivative instruments qualify for hedge accounting as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into OCI and recognized in revenues or cost of sales and operations in the periods during which the underlying physical transactions occur. We have determined that our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133. At September 30, 2003, there was a gain of $28.8 million, deferred in OCI related to our commodity price risk activities. The amount included in earnings due to changes in the fair value of derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective for the nine months ended September 30, 2003 and 2002, was a loss of $1.6 million and a loss of $2.1 million, respectively.

Controlled Trading Program

        From time to time, we experience net unbalanced positions as a result of production and delivery variances associated with our lease purchase activities. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to 500,000 barrels. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues. There were no open positions under this program at September 30, 2003. The realized earnings impact related to these derivatives for the nine months ended September 30, 2003 and 2002 was a loss of $0.2 million and $0.3 million, respectively.

Interest Rate Risk Hedging

        We utilize various products, such as interest rate swaps, collars and treasury locks, to hedge interest obligations on outstanding debt and anticipated debt issuances. During the first quarter of 2003, we converted a $50.0 million treasury lock into a 10-year LIBOR-based swap that becomes effective in March 2004, as discussed below, contemporaneously with the expiration of an existing $50.0 million LIBOR-based swap. The instruments outstanding at September 30, 2003, consist of three separate interest rate swaps with an aggregate notional principal amount of $100.0 million outstanding at any one time. The interest rate swaps are based on LIBOR rates and provide for a LIBOR rate of 5.1% for a $50.0 million notional principal amount expiring October 2006, a LIBOR rate of 4.3% for a $50.0 million notional principal amount expiring March 2004 and a LIBOR rate of 5.8% for a $50.0 million notional principal amount that commences in March 2004 and expires in March 2014. All of these instruments are placed with what we believe are large creditworthy financial institutions. Interest on the underlying debt is based on LIBOR plus a margin.

        These instruments qualify for hedge accounting as cash flow hedges in accordance with SFAS 133. The effective portion of changes in fair values of these hedges is recorded in OCI until the related hedged item impacts earnings. At September 30, 2003, there was a loss of $10.6 million deferred in OCI related to our interest rate risk activities. For the nine months ended September 30, 2003 and 2002, there were no amounts recognized into earnings related to hedge ineffectiveness.

        At September 30, 2003, our weighted average interest rate, excluding non-use and facilities fees, was approximately 5.9%. This rate is based on our average September 2003 debt balances, our credit

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spread under our credit facilities and the combination of our fixed rate debt floating rate indices and current interest rate hedges. We have locked-in interest rates (excluding the credit spread under the credit facilities) for approximately 66% of our total long-term debt through October 2006, and 55% for the period from October 2006 through September 2012.

Currency Exchange Rate Risk Hedging

        Because a significant portion of our Canadian business is conducted in Canadian dollars (CAD), we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include forward exchange contracts, forward extra option contracts and cross currency swaps.

        At September 30, 2003, we had forward exchange contracts and forward extra option contracts that allow us to exchange $3.0 million Canadian for at least $1.9 million U.S. quarterly during 2003 (based on a Canadian-U.S. dollar exchange rate of 1.54). At September 30, 2003, we also had cross currency swap contracts for an aggregate notional principal amount of $23.0 million, effectively converting this amount of our senior secured term loan to $35.6 million of Canadian dollar debt (based on a Canadian-U.S. dollar exchange rate of 1.55). The terms of this contract mirror the term loan, matching the amortization schedule and final maturity in May 2006. All of these instruments are placed with what we believe are large creditworthy financial institutions.

        The forward exchange contracts and forward extra option contracts qualify for hedge accounting as cash flow hedges, in accordance with SFAS 133. Such derivative activity resulted in a loss of $0.2 million deferred in OCI at September 30, 2003. For the nine months ended September 30, 2003 and 2002, there were no amounts recognized into earnings related to hedge ineffectiveness. The cross currency swaps qualify for hedge accounting as fair value hedges, also in accordance with SFAS 133. Therefore, the change in the fair value of these instruments is recognized currently in earnings. The earnings impact related to our cross currency swaps was a loss of $0.1 million for the nine months ended September 30, 2003 and a nominal amount for the nine months ended September 30, 2002.

Note 9—Commitments and Contingencies

Litigation

        We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Indemnities

        In November, 2002, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others ("FIN 45"). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We are party to various contracts entered into in the ordinary course of business that contain indemnity provisions pursuant to which we indemnify the counterparties against various expenses. Our indemnity

16

obligations are contingent upon the occurrence of events or circumstances specified in the contracts. No such events or circumstances have occurred at this time, and we do not consider our liability under such indemnity provisions, individually or in the aggregate, to be material to our financial position or results of operations.

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. We believe that our reserve for environmental liabilities is adequate. However, 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.

Contingent Equity Issuance

        In connection with the CANPET acquisition in July 2001, approximately $26.5 million Canadian dollars of the purchase price, payable in common units, was deferred subject to various performance objectives being met. If these objectives are met as of December 31, 2003, the deferred amount is payable on April 30, 2004. The number of common units issued in satisfaction of the deferred payment will depend upon the average trading price of our common units for a ten-day trading period prior to the payment date and the Canadian and U.S. dollar exchange rate on the payment date. In addition, an amount will be paid equivalent to the distributions that would have been paid on the common units had they been outstanding since the acquisition was consummated. At our option, the deferred payment may be paid in cash rather than the issuance of units. We believe that it is probable that the objectives will be met and the deferred amount will be paid in April 2004, however, it is not determinable beyond a reasonable doubt. Assuming the tests are met as of December 31, 2003, and the entire obligation is satisfied with common units, based on the foreign exchange rate and the ten-day average unit price in effect at September 30, 2003, (1.35 Canadian to U.S. dollar exchange rate and $30.36 per unit price) approximately 650,000 units would be issued.

Asset Retirement Obligation

        In June 2001, the FASB issued SFAS No. 143 "Asset Retirement Obligations." SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the time of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Effective January 1, 2003, we adopted SFAS 143, as required. Determination of the amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. The majority of our assets, primarily related to our pipeline operations segment, have obligations to perform remediation and, in some instances, removal activities when the asset is retired. However, the fair value of the asset retirement obligations cannot be reasonably estimated, as the settlement dates are indeterminate. We will record such asset retirement obligations in the period in which we can reasonably determine the settlement dates. The adoption of this statement did not have a material

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impact on our financial position, results of operations or cash flows. See Note 2 for the accounting treatment of the shutdown of the Rancho Pipeline System.

Other

        Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets (including our nation's pipeline infrastructure) may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. We have instituted security measures and procedures in conformity with Department of Transportation ("DOT") guidance. We will institute, as appropriate, additional security measures or procedures indicated by the DOT or the Transportation Safety Administration (an agency of the Department of Homeland Security, which is in the transitional phase of assuming responsibility from the DOT). We cannot assure you that these or any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not.

        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 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 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) our Pipeline Operations through which we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities; and (2) our Gathering, Marketing, Terminalling and Storage Operations through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on (i) gross margin (excluding depreciation), (ii) gross profit (excluding depreciation), which is gross margin (excluding depreciation) less general and administrative expenses and (iii) on an annual basis, maintenance capital. Maintenance capital consists of expenditures required to maintain the existing operating capacity of partially or fully depreciated assets or extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with

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existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred.

			Pipeline			Gathering, Marketing, Terminalling & Storage			Total
			(in millions)
Three Months Ended September 30, 2003
Revenues:
	External Customers		$	148.3		$	2,905.3		$	3,053.6
	Intersegment(1)			16.1			0.2			16.3
		Total revenues of reportable segments		164.4			2,905.5			3,069.9
Gross margin (excluding depreciation)				30.1			20.6			50.7
General and administrative expenses(2)				(7.2	)		(11.0	)		(18.2	)
Gross profit (excluding depreciation)			$	22.9		$	9.6		$	32.5
LTIP accrual(3)			$	(3.0	)	$	(4.4	)	$	(7.4	)
Noncash SFAS 133 impact(4)			$	—		$	(2.9	)	$	(2.9	)
Maintenance capital			$	1.0		$	0.3		$	1.3
Three Months Ended September 30, 2002
Revenues:
	External Customers		$	123.4		$	2,220.7		$	2,344.1
	Intersegment(1)			7.0			—			7.0
		Total revenues of reportable segments		130.4			2,220.7			2,351.1
Gross margin (excluding depreciation)				23.0			21.3			44.3
General and administrative expenses(2)				(3.3	)		(8.2	)		(11.5	)
Gross profit (excluding depreciation)			$	19.7		$	13.1		$	32.8
Noncash SFAS 133 impact(4)			$	—		$	(0.4	)	$	(0.4	)
Maintenance capital			$	0.5		$	0.7		$	1.2

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			Pipeline			Gathering, Marketing, Terminalling & Storage			Total
			(in millions)
Nine Months Ended September 30, 2003
Revenues:
	External Customers		$	450.6		$	8,594.1		$	9,044.7
	Intersegment(1)			38.5			0.7			39.2
		Total revenues of reportable segments		489.1			8,594.8			9,083.9
Gross margin (excluding depreciation)				83.5			80.0			163.5
General and administrative expenses(2)				(16.3	)		(27.1	)		(43.4	)
Gross profit (excluding depreciation)			$	67.2		$	52.9		$	120.1
LTIP accrual(3)			$	(3.0	)	$	(4.4	)	$	(7.4	)
Noncash SFAS 133 impact(4)			$	—		$	(1.7	)	$	(1.7	)
Maintenance capital			$	4.8		$	0.7		$	5.5
Nine Months Ended September 30, 2002
Revenues:
	External Customers		$	320.2		$	5,554.6		$	5,874.8
	Intersegment(1)			13.9			—			13.9
		Total revenues of reportable segments		334.1			5,554.6			5,888.7
Gross margin (excluding depreciation)				60.3			64.1			124.4
General and administrative expenses(2)				(9.9	)		(23.5	)		(33.4	)
Gross profit (excluding depreciation)			$	50.4		$	40.6		$	91.0
Noncash SFAS 133 impact(4)			$	—		$	(2.1	)	$	(2.1	)
Maintenance capital			$	2.7		$	1.3		$	4.0

(1)

Intersegment sales are based on published tariff rates or contracted amounts at market prices.

(2)

General and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgement by management and will continue to be based on the business activities that exist during each period.

(3)

Includes $0.4 million and $1.0 million related to the accrual for our LTIP included in gross margin for our Pipeline and our Gathering, Marketing, Terminalling and Storage segments, respectively. In addition, $2.6 million and $3.4 million related to the accrual for our LTIP are included in general & administrative expenses for our Pipeline and our Gathering, Marketing, Terminalling and Storage segments, respectively.

(4)

Amounts related to SFAS 133 are included in revenues, gross margin (excluding depreciation) and gross profit (excluding depreciation). When we internally evaluate our results, we exclude the noncash, mark-to-market impact of SFAS 133.

Note 11—Recent Accounting Pronouncements

        The following recently issued accounting standard has not yet been adopted. This standard will impact the preparation of our financial statements; however, we do not believe that this standard will materially impact our financial position, results of operations or cash flows.

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        In July 2003, the Emerging Issues Task Force ("EITF") reached consensus on certain issues in EITF Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not "Held for Trading Purposes" As Defined in EITF Issue No. 02-3." The consensus provides guidance as to whether gains and losses on physically settled derivative contracts not "held for trading purposes" should be reported in the income statement on a gross or net basis. EITF 03-11 is effective for arrangements entered into after September 30, 2003.

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Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

        Plains All American Pipeline, L.P., is a publicly traded Delaware limited partnership (the "Partnership"), formed in 1998 and is engaged in interstate and intrastate marketing, transportation and terminalling of crude oil and liquified petroleum gas ("LPG"). Our operations are conducted directly and indirectly through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana and the Canadian provinces of Alberta and Saskatchewan.

        During the first quarter of 2003, new Securities and Exchange Commission regulations regarding the use of non-GAAP financial measures became effective. As a result of our efforts to comply with these new regulations, we have made certain changes to the content and presentation of information in Management's Discussion and Analysis of Financial Condition and Results of Operations. Although not excluded here, when we internally evaluate our results for performance against expectations, public guidance and trend analysis, we exclude the noncash, mark-to-market impact of Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" resulting from (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. The majority of these instruments serve as economic hedges that offset future physical positions not reflected in current results. Therefore, the SFAS 133 adjustment to net income is not a complete depiction of the economic substance of the transaction, as it only represents the derivative side of these transactions and does not take into account the offsetting physical position. In addition, the impact will vary from quarter to quarter based on market prices at the end of the quarter, which are impossible for us to control or forecast.

        Internally, we also consider in our analysis of operating results the impact of other items that we believe impact comparability between periods. To comply with the new regulations, we have omitted certain adjustments and reconciliations related to these items that have been presented in the past. We have also changed the format of certain tables presented in the discussion of our results of operations. In addition, certain reclassifications have been made to prior period amounts to conform to current period presentation. Where appropriate, we have noted that reported results include the effects of items we consider to impact comparability between periods. Overall, we believe the discussion and presentation provides an accurate and thorough analysis of our results of operations and financial condition. Additionally, we maintain on our website (www.paalp.com) a reconciliation of all non-GAAP financial information that we disclose to the most comparable GAAP measures. To access the information, investors should click on the "Non-GAAP Reconciliation" link on our home page.

Acquisitions

        We completed several acquisitions during 2002 and 2003 that have impacted the results of operations and liquidity discussed herein. The cash portion of these acquisitions was funded from cash on hand and borrowings under our revolving credit facility. These acquisitions are discussed below and our ongoing acquisition activity is discussed further in "Liquidity and Capital Resources."

ArkLaTex Pipeline System

        In September 2003, we made a deposit (approximately $17.0 million) to acquire the ArkLaTex Pipeline System from Link Energy (formerly EOTT Energy). The ArkLaTex Pipeline System consists of 240 miles of active crude oil gathering and mainline pipelines and connects to our Red River Pipeline System near Sabine, Texas. Also included in the transaction were 470,000 barrels of active crude oil storage capacity, the assignment of certain of Link Energy's crude oil supply contracts and

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crude oil linefill and working inventory comprised of approximately 108,000 barrels. The total purchase price of approximately $21.3 million is comprised of a) $14.0 million of cash paid to Link Energy for the pipeline system, b) $2.9 million of cash paid to Link Energy to purchase crude oil linefill and working inventory, c) $3.6 million for transaction costs and estimated near-term capital costs and d) $0.8 million associated with the satisfaction of outstanding claims for accounts receivable and inventory balances. The near-term capital costs are associated with modifications required to enhance the capacity and validate and improve the integrity of the pipeline (which are expected to extend the life and improve the usefulness of the pipeline system) and enable us to operate it in conformity with our policies and specifications and are expected to be incurred within the next year. A portion of the purchase price has been allocated to the crude oil supply contracts; however, we are in the process of evaluating certain estimates made in the purchase price allocation. Thus, the allocation is subject to refinements. The acquisition closed and was effective on October 1, 2003, and will be included in our Pipeline Operations and our Gathering, Marketing, Terminalling and Storage segments, as appropriate.

Other Acquisitions

        During the first half of 2003, we made six acquisitions from various entities for an aggregate purchase price of $85.7 million. 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 $3.0 million that was allocated to investment in affiliates and $0.5 million that was allocated to goodwill and other intangible assets, the aggregate purchase price was allocated to property and equipment.

2002 Acquisitions

        In August 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 8.9 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the "Shell acquisition") for approximately $324 million. During the remainder of 2002, we made two acquisitions consisting of domestic gathering and marketing assets and an equity interest in a pipeline system for an aggregate purchase price of approximately $15.9 million.

Results of Operations

        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 margin activities; and (2) our Gathering, Marketing, Terminalling and Storage Operations, through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on (i) gross margin (excluding depreciation), (ii) gross profit (excluding depreciation), which is gross margin (excluding depreciation) less general and administrative expenses and (iii) on an annual basis, maintenance capital. Maintenance capital consists of 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. Our current estimate of maintenance capital expenditures for 2003 is approximately $6.9 million. We monitor maintenance capital expenditures on an annual basis, since these capital projects can overlap quarters and may be impacted by weather, permitting and other uncontrollable delays. Accordingly, no period-by-period analysis is provided, except on an annual basis.

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Three Months Ended September 30, 2003 and 2002

        For the three months ended September 30, 2003, we reported net income of $11.9 million on total revenues of $3.1 billion compared to net income for the same period in 2002 of $16.3 million on total revenues of $2.3 billion. Included in the results of operations for the third quarter of 2003 and 2002 are certain items that impact the comparability between periods. These items include amounts related to accruals for the probable vesting of restricted units granted under our Long-Term Incentive Plan ("LTIP"). Under generally accepted accounting principles, we are required to recognize an expense when vesting of LTIP units becomes probable as determined by management at the end of the period (See Outlook, Vesting of Unit Grants Under Long-Term Incentive Plan). The compensation expense accrued relates to many years of service (thus we have included this amount in the following table of items impacting comparability), and culminates with both the early conversion of 25% of our subordinated units to common units and the related 90-day "continued employment" period. (see Note 7 to the Consolidated Financial Statements). In addition, and as discussed previously, the majority of instruments we are required to mark-to-market at the end of each quarterly period pursuant to SFAS 133 do serve as economic hedges that offset future physical positions not reflected in current results. Therefore, we believe mark-to-market adjustments to net income required under SFAS 133 do not provide a complete depiction of the economic substance of the transaction, as it only represents the derivative side of these transactions and does not take into account the offsetting physical position. In addition, the impact will vary from quarter to quarter based on market prices at the end of the quarter, which are impossible for us to control or forecast, and the SFAS 133 adjustments will reverse in future periods. Accordingly, when we internally evaluate our results for performance against expectations, public guidance and trend analysis, we exclude the non-cash, mark-to-market impact of SFAS 133. Thus, we present the impact of the SFAS 133 adjustments because we believe such amounts affect the comparison of the fundamental operating results for the periods presented. Our third quarter 2003 net income also includes a $0.2 million loss related to unamortized debt issue costs on early extinguishment of debt. This loss relates to a $34 million prepayment on our Senior secured term B loan which was made in anticipation of restructuring our existing secured credit facilities into unsecured credit facilities during the fourth quarter (See Note 4 to the Consolidated Financial Statements).

        The items discussed above are included in net income in the period indicated and impact the comparability between periods as shown below:

		Three months ended September 30,
		2003			2002
		(in millions)
Items Impacting Comparability
	LTIP accrual	$	(7.4	)	$	—
	SFAS 133 Loss		(2.9	)		(0.4	)
	Loss on early extinguishment of debt		(0.2	)		—
	Total of items impacting comparability	$	(10.5	)	$	(0.4	)

24

        The following table reflects our results of operations for each segment:

	Pipeline Operations			Gathering, Marketing, Terminalling & Storage
	(in millions)
Three Months Ended September 30, 2003(1)
Revenues	$	164.4		$	2,905.5
Cost of sales and operations (excluding depreciation and LTIP accrual)		(133.9	)		(2,883.9	)
LTIP accrual—operations		(0.4	)		(1.0	)
Gross margin (excluding depreciation)		30.1			20.6
General and administrative expenses (excluding LTIP accrual)(2)		(4.6	)		(7.6	)
LTIP accrual—general and administrative		(2.6	)		(3.4	)
Gross profit (excluding depreciation)	$	22.9		$	9.6
Noncash SFAS 133 impact(3)	$	—		$	(2.9	)
Maintenance capital	$	1.0		$	0.3
Three Months Ended September 30, 2002(1)
Revenues	$	130.4		$	2,220.7
Cost of sales and operations (excluding depreciation)		(107.4	)		(2,199.4	)
Gross margin (excluding depreciation)		23.0			21.3
General and administrative expenses(2)		(3.3	)		(8.2	)
Gross profit (excluding depreciation)	$	19.7		$	13.1
Noncash SFAS 133 impact(3)	$	—		$	(0.4	)
Maintenance capital	$	0.5		$	0.7

(1)

Revenues and costs of sales and operations include intersegment amounts.

(2)

General and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)

Amounts related to SFAS 133 are included in revenues, gross margin (excluding depreciation), and gross profit (excluding depreciation).

Pipeline Operations

        As of September 30, 2003, we owned and operated over 6,200 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 (tariff activities), as well as barrel exchanges and buy/sell arrangements (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. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The gross margin (excluding depreciation) generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable costs of operating the pipeline. Gross margin (excluding depreciation) from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

25

The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated:

				Three months ended September 30,
				2003			2002
Operating Results (in millions)(1)
	Tariff activities revenues			$	40.4		$	31.5
	Margin activities revenues				124.0			98.9
	Total pipeline operations revenues				164.4			130.4
	Cost of sales and operations (excluding depreciation and LTIP accrual)				(133.9	)		(107.4	)
	LTIP accrual—operations				(0.4	)		—
	Gross Margin (excluding depreciation)				30.1			23.0
	General and administrative expenses (excluding LTIP accrual)(2)				(4.6	)		(3.3	)
	LTIP accrual—general and administrative				(2.6	)		—
	Gross Profit (excluding depreciation)			$	22.9		$	19.7
	Maintenance capital			$	1.0		$	0.5
Average Daily Volumes (thousands of barrels per day)(3)
	Tariff activities
		All American			59			68
		Basin			301			157
		Other domestic			328			260
		Canada			210			201
	Total tariff activities				898			686
	Margin activities				77			71
			Total		975			757

(1)

Revenues and cost of sales and operations include intersegment amounts.

(2)

General and administrative ("G&A") expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)

Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period.

        Total average daily volumes transported were approximately 975,000 barrels per day and 757,000 barrels per day for the three months ended September 30, 2003 and 2002, respectively. As discussed above, we have completed a number of acquisitions during 2003 and 2002 that have impacted the

26

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 September 30,
		2003	2002
		(thousands of barrels per day)
Tariff activities(1)
	2003 acquisitions	108	—
	2002 acquisitions	375	282
	All other pipeline systems	415	404
	Total tariff activities average daily volumes	898	686

(1)

Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period.

        Average daily volumes from our tariff activities were approximately 898,000 barrels per day compared to approximately 686,000 barrels per day for the prior year quarter. Approximately 201,000 barrels per day of the increase in the current year quarter is due to volumes transported on the pipelines acquired in 2003 and 2002, including an increase of approximately 94,000 barrels per day on the assets acquired in the Shell acquisition because of their inclusion for the entire period in 2003 compared to 2 months in 2002. Volumes on all other pipeline systems increased by approximately 11,000 barrels per day to approximately 415,000 barrels per day. The increase is primarily related to a 9,000 barrel per day increase in volumes from our Canadian pipelines and a 13,000 barrel per day increase in our West Texas Gathering System volumes, offset by a decrease of 9,000 barrels per day in our All American tariff volumes attributable to a decline in California outer continental shelf ("OCS") production. The increase in our Canadian volumes primarily resulted from the completion of capital expansion projects that allowed for additional volumes on certain of our Canadian pipelines, coupled with the impact of the completion of a refinery turnaround. Our West Texas Gathering System has benefited from the shutdown of the Rancho pipeline. In addition, during the third quarter of 2003, we also transported additional barrels as a result of refinery problems in West Texas that temporarily diverted crude oil from other systems.

        Total revenues from our pipeline operations were approximately $164.4 million and $130.4 million for the three months ended September 30, 2003 and 2002, respectively. The increase in revenues was primarily related to our margin activities, which increased by approximately $25.1 million in the third quarter of 2003. This increase was related to higher volumes on our buy/sell arrangements in the current period, coupled with higher average prices on our margin activity on our San Joaquin Valley gathering system in the 2003 period as compared to the 2002 period. However, this business is a margin business and although revenues and cost of sales are impacted by the absolute level of crude oil prices, there is a limited impact on gross margin.

27

        Revenues from our tariff activities increased approximately 28% or $8.9 million. The following table reflects our revenues from our tariff activities by year of acquisition from their date of acquisition for comparison purposes:

		Three months ended September 30,
		2003		2002
		(in millions)
Tariff activities revenues(1)
	2003 acquisitions	$	4.1	$	—
	2002 acquisitions		14.8		10.4
	All other pipeline systems		21.5		21.1
	Total tariff activities	$	40.4	$	31.5

(1)

Revenues include intersegment amounts.

        Total revenues from our tariff activities were approximately $40.4 million and $31.5 million for the three months ended September 30, 2003 and 2002, respectively. The increase in the third quarter of 2003 is predominately related to the inclusion of $18.9 million of revenues from the businesses acquired in 2003 and 2002. Revenues from pipeline systems acquired in 2002 have increased to $14.8 million from $10.4 million primarily the result of the inclusion of only two months' contribution in 2002 from the assets acquired in the Shell acquisition. Revenues from all other pipeline systems increased approximately $0.4 million to $21.5 million. This increase resulted principally from our Canadian operations. Canadian revenues increased approximately $1.1 million in the 2003 period primarily due to expanded capacity, higher tariffs and a $0.9 million favorable exchange rate impact. The favorable exchange rate impact has resulted from a decrease in the Canadian to U.S. dollar exchange rate to an average rate of 1.38 for the three months ended September 30, 2003, from an average rate of 1.56 for the three months ended September 30, 2002. Higher volumes on the West Texas Gathering System also contributed to the increase in tariff revenues from all other systems. These increases were partially offset by lower revenues from the All American System, on which we receive the highest per barrel tariffs among our pipeline systems.

        As a result of these factors, our pipeline operations gross margin (excluding depreciation) increased 31% to approximately $30.1 million for the quarter ended September 30, 2003, from $23.0 million for the prior year period, an increase of approximately $7.1 million. Such results incorporate an increase in operating expenses to $15.0 million in the 2003 period from $12.9 million in the 2002. This increase includes $0.4 million related to the accrual made for the probable vesting of unit grants under our LTIP. The remaining increase is predominately related to our continued growth, primarily from acquisitions, coupled with higher utility costs. In addition, gross margin (excluding depreciation) includes a $0.6 million favorable impact resulting from the decrease in the average Canadian dollar to U.S. dollar exchange rate for the 2003 period as compared to the 2002 period.

        General and administrative expenses increased approximately $3.9 million between comparable periods, primarily as a result of a $2.6 million accrual related to the probable vesting of unit grants under our LTIP. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has increased in the 2003 period as our pipeline operations have grown. Including the impact of the items discussed above, gross profit (excluding depreciation) was approximately $22.9 million in the third quarter of 2003, an increase of 16% as compared to the $19.7 million reported for the quarter ended September 30, 2002. Gross profit (excluding depreciation) includes a $0.5 million favorable impact resulting from the decrease in the average Canadian-dollar to U.S.-dollar exchange rate for the 2003 period as compared to the 2002 period.

28

Gathering, Marketing, Terminalling and Storage Operations

        Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased crude oil and liquefied petroleum gas ("LPG") plus the sale of additional barrels exchanged through buy/sell arrangements entered into to enhance the margins of the gathered and bulk-purchased volumes. Gross margin from our gathering and marketing activities is dependent on our ability to sell crude oil and LPG at a price in excess of our aggregate cost. These operations are margin businesses and are not directly affected by the absolute level of prices, but are affected by overall levels of supply and demand for crude oil and LPG and fluctuations in market-related indices. Accordingly, an increase or decrease in revenues is not necessarily an indication of segment performance.

        We own and operate approximately 23.2 million barrels of above-ground crude oil terminalling and storage facilities, including a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to as the Cushing Interchange, is one of the largest crude oil market hubs in the United States and the designated delivery point for New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling." Approximately 11.0 million barrels of our 23.2 million barrels of tankage is used primarily in our Gathering, Marketing, Terminalling and Storage Operations and the balance is used in our Pipeline Operations segment. On a stand alone basis, gross margin from terminalling and storage activities is dependent on the throughput 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.

        Crude oil prices have historically been very volatile and cyclical. Over the last 13 years, the NYMEX benchmark price has ranged from as high as $40.00 per barrel to as low as $10.00 per barrel. Our business strategy recognizes this volatility and the inherent inefficiencies such conditions create. Accordingly, we have deliberately configured our assets and integrated our activities in this segment in an effort to provide a counter-cyclical balance between our gathering and marketing activities and our terminalling and storage activities, and execute different hedging strategies to stabilize and enhance margins and reduce the negative impact of crude oil market volatility.

        The volatility in the market place continued as during this quarter the NYMEX benchmark price of crude oil ranged from as high as $32.85 per barrel to as low as $26.65 per barrel. This volatility, in conjunction with our hedging strategies, enhanced the returns of our gathering and marketing activities. Beginning in September 2003, the steep backwardation that existed in the crude oil markets for most of the first eight months of the year subsided. Market conditions during the third quarter of 2002 were less favorable as the crude oil market alternated between periods of weak contango and strong backwardation.

        As a result of completing our Phase III expansion at our Cushing facility, total tankage dedicated to our Gathering, Marketing, Terminalling and Storage Operations was approximately 1.0 million barrels greater in the third quarter of 2003 relative to the third quarter of 2002. A portion of such tankage was employed in hedging activities related to our gathering and marketing activities in the third quarter of 2003.

29

        The following table sets forth our operating results from our Gathering, Marketing, Terminalling and Storage Operations segment for the periods indicated:

			Three months ended September 30,
			2003			2002
Operating Results (in millions)(1)
	Revenues		$	2,905.5		$	2,220.7
	Cost of sales and operations (excluding depreciation and LTIP accrual)			(2,883.9	)		(2,199.4	)
	LTIP accrual—operations			(1.0	)		—
	Gross Margin (excluding depreciation)			20.6			21.3
	General and administrative expenses (excluding LTIP accrual)(2)			(7.6	)		(8.2	)
	LTIP accrual—general and administrative			(3.4	)		—
	Gross Profit (excluding depreciation)		$	9.6		$	13.1
	Noncash SFAS 133 impact(3)		$	(2.9	)	$	(0.4	)
	Maintenance capital		$	0.3		$	0.7
Average Daily Volumes (thousands of barrels per day except as otherwise noted)(4)
	Crude oil lease gathering			429			408
	Crude oil bulk purchases			96			72
		Total		525			480
	LPG sales			37			32
	Cushing Terminal throughput			214			118
	Storage leased to third parties, monthly average volumes			1,099			591

(1)

Revenues and cost of sales and operations include intersegment amounts.

(2)

General and administrative ("G&A") expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)

Amounts related to SFAS 133 are included in revenues, gross margin (excluding depreciation) and gross profit (excluding depreciation).

(4)

Volumes associated with acquisitions represent weighted averaged daily amounts for the number of days we actually owned the assets over the total days in the period.

        Because of the overall counter-cyclical balance of our assets and the flexibility embedded in our business strategy, the benefit we received from backwardation in the market, the increase in lease gathering volumes, volatile market conditions and increased tankage available to our gathering and marketing business in the third quarter of 2003, more than offset the adverse impact of reduced storage activities. During much of the third quarter of 2002, the crude oil market was in contango. In addition, the Canadian dollar to U.S. dollar exchange rate decreased to an average rate of 1.38 for the three months ended September 30, 2003, from an average rate of 1.56 for the three months ended September 30, 2002, which resulted in a favorable impact on the results reported for our Canadian operations.

        The increase in earnings we realized from the factors discussed above was offset by the items impacting comparability listed in the table below. The resulting gross margin (excluding depreciation)

30

for the quarter was $20.6 million compared to $21.3 million in 2002. The following items impact the comparability of gross margin (excluding depreciation) for the periods presented:

		Three months ended September 30,
		2003			2002
		(in millions)
Items Impacting Comparability
	LTIP accrual	$	(1.0	)	$	—
	SFAS 133 Loss		(2.9	)		(0.4	)
	Total of items impacting comparability	$	(3.9	)	$	(0.4	)

        Operating expenses included in gross margin (excluding depreciation) increased to approximately $19.6 million in the current period from $15.9 million in the prior year period. This increase included the $1.0 million LTIP accrual shown above. The remaining increase was partially related to our continued growth, primarily from acquisitions, coupled with increased regulatory compliance activities and higher fuel costs. These items were partially offset by the approximately $0.9 million favorable impact from the decrease in the Canadian dollar to U.S. dollar exchange rate in the 2003 period as compared to the 2002 period.

        General and administrative expenses increased to $11.0 million in the current period from $8.2 million in the 2002 period. Included in the 2003 amount is $3.4 million related to the accrual for the probable vesting of unit grants under our LTIP. The percentage of indirect costs allocated to the Gathering, Marketing, Terminalling and Storage Operations segment has decreased from period to period as our pipeline operations have grown, partially offsetting the impact of the inclusion of the LTIP accrual. Current quarter gross profit (excluding depreciation) of $9.6 million includes $3.9 million related to the items impacting comparability listed above as well as an additional $3.4 million of expense related to the probable vesting of unit grants under our LTIP accrual included in general and administrative expenses. Partially offsetting these items is the approximately $0.5 million favorable impact from the decrease in the Canadian dollar to U.S. dollar exchange rate.

        In addition to market conditions and our hedging activities, the primary drivers of the performance of our gathering, marketing, terminalling and storage operations segment are crude oil lease gathered volumes and LPG sales volumes. Crude oil bulk purchase volumes are not considered a driver as they are primarily used to enhance margins of lease gathered barrels. Gross profit per barrel (excluding depreciation) including the items impacting comparability for the quarters ended September 30, 2003 and 2002, was $0.22 per barrel and $0.32 per barrel, respectively.

        For the quarter ended September 30, 2003, we gathered from producers, using our assets or third-party assets, approximately 429,000 barrels of crude oil per day, an increase of 5% over similar activities in the third quarter of 2002. In addition, we purchased in bulk, primarily at major trading locations, approximately 96,000 barrels of crude oil per day in the 2003 period and approximately 72,000 barrels per day in the 2002 period. Storage leased to third parties at our Cushing facility increased to an average of 1.1 million barrels per month in the current year quarter from an average of 0.6 million barrels per month in the third quarter of 2002. Cushing Terminal throughput volumes averaged approximately 214,000 barrels per day and 118,000 barrels per day for the quarters ended September 30, 2003 and 2002, respectively. Also during the quarter, we marketed approximately 37,000 barrels per day of LPG, an increase of approximately 16% over the approximately 32,000 barrels per day marketed in the third quarter of 2002.

        Revenues from our gathering, marketing, terminalling and storage operations were approximately $2.9 billion and $2.2 billion for the quarters ended September 30, 2003 and 2002, respectively.

31

Revenues and cost of sales and operations (excluding depreciation) for 2003 were impacted by higher average prices and higher crude oil lease gathering volumes in the 2003 period as compared to the 2002 period. The average NYMEX price for crude oil was $30.26 per barrel and $28.27 per barrel for the third quarter of 2003 and 2002, respectively.

Other Expenses

Depreciation and Amortization

        Depreciation and amortization expense related to operations was approximately $10.5 million for the quarter ended September 30, 2003, compared to $7.7 million for the same period of 2002. The increase relates to an inclusion of a full quarter of depreciation for the Shell acquisition in 2003 compared to only two months in 2002, the completion of numerous smaller acquisitions in 2003 and various capital expansion projects. Depreciation and amortization expense related to general and administrative items increased to $1.5 million in the third quarter of 2003 from $1.3 million in the third quarter of 2002. Debt amortization costs included in depreciation and amortization expense were $1.0 million in the third quarter of both 2003 and 2002.

Interest Expense

        Interest expense increased approximately $1.4 million to $8.8 million for the quarter ended September 30, 2003, from $7.4 million for the comparable 2002 period. The increase was primarily related to an increase in the average debt balance during the 2003 period to approximately $532.3 million from approximately $482.3 million in the 2002 period, which resulted in additional interest expense of approximately $0.7 million. The higher average debt balance was primarily due to the portion of the Shell acquisition that was not financed with equity. This debt was outstanding for the entire quarter in 2003 versus only a portion of the quarter in 2002. Also, increased commitment and other fees coupled with lower capitalized interest resulted in approximately $0.5 million of the increase in the 2003 period. In addition, our weighted average interest rate increased slightly during the current year quarter to 5.9% versus 5.8% in the third quarter of 2002, which increased our interest expense by approximately $0.2 million. Although the interest rate change was slight, it was the net result of various factors that included an increase in the amount of fixed rate, long-term debt, long-term interest rate hedges and declining short-term interest rates. In mid-September 2002, we issued $200 million of ten-year bonds bearing a fixed interest rate of 7.75%. In the fourth quarter of 2002 and the first quarter of 2003, the company entered into hedging arrangements to lock in interest rates on approximately $50 million of its floating rate debt. In addition, the average three-month LIBOR rate declined from approximately 1.8% during the third quarter of 2002 to approximately 1.1% during the three months ended September 30, 2003. The net impact of these factors, increased commitment fees and changes in average debt balances increased the average interest rate by 0.1%.

Nine Months Ended September 30, 2003 and 2002

        For the nine months ended September 30, 2003, we reported net income of $59.6 million on total revenues of $9.0 billion compared to net income for the same period in 2002 of $47.5 million on total revenues of $5.9 billion.

32

        The items included in the following table are included in net income in the period indicated and impact the comparability between periods:

		Nine months ended September 30,
		2003			2002
		(in millions)
Items Impacting Comparability
	LTIP accrual	$	(7.4	)	$	—
	SFAS 133 Loss		(1.7	)		(2.1	)
	Loss on early extinguishment of debt		(0.2	)		—
	Total of items impacting comparability	$	(9.3	)	$	(2.1	)

        The following table reflects our results of operations for each segment:

	Pipeline Operations			Gathering, Marketing, Terminalling & Storage
	(in millions)
Nine Months Ended September 30, 2003(1)
Revenues	$	489.1		$	8,594.8
Cost of sales and operations (excluding depreciation and LTIP accrual)		(405.2	)		(8,513.8	)
LTIP accrual—operations		(0.4	)		(1.0	)
Gross margin (excluding depreciation)		83.5			80.0
General and administrative expenses (excluding LTIP accrual)(2)		(13.7	)		(23.7	)
LTIP accrual—general and administrative		(2.6	)		(3.4	)
Gross profit (excluding depreciation)	$	67.2		$	52.9
Noncash SFAS 133 impact(3)	$	—		$	(1.7	)
Maintenance capital	$	4.8		$	0.7
Nine Months Ended September 30, 2002(1)
Revenues	$	334.1		$	5,554.6
Cost of sales and operations (excluding depreciation)		(273.8	)		(5,490.5	)
Gross margin (excluding depreciation)		60.3			64.1
General and administrative expenses(2)		(9.9	)		(23.5	)
Gross profit (excluding depreciation)	$	50.4		$	40.6
Noncash SFAS 133 impact(3)	$	—		$	(2.1	)
Maintenance capital	$	2.7		$	1.3

(1)

Revenues and costs of sales and operations include intersegment amounts.

(2)

General and administrative expenses (G&A) reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)

Amounts related to SFAS 133 are included in revenues, gross margin (excluding depreciation), and gross profit (excluding depreciation).

33

Pipeline Operations

        The following table sets forth our operating results from our Pipeline Operations segment for the periods indicated:

				Nine months ended September 30,
				2003			2002
Operating Results (in millions)(1)
	Tariff activities revenues			$	112.4		$	72.2
	Margin activities revenues				376.7			261.9
	Total pipeline operations revenues				489.1			334.1
	Cost of sales and operations (excluding depreciation and LTIP accrual)				(405.2	)		(273.8	)
	LTIP accrual—operations				(0.4	)		—
	Gross Margin (excluding depreciation)				83.5			60.3
	General and administrative expenses (excluding LTIP accrual)(2)				(13.7	)		(9.9	)
	LTIP accrual—general and administrative				(2.6	)		—
	Gross Profit (excluding depreciation)			$	67.2		$	50.4
	Maintenance capital			$	4.8		$	2.7
Average Daily Volumes (thousands of barrels per day)(3)
	Tariff activities
		All American			60			65
		Basin			264			53
		Other domestic			283			189
		Canada			191			186
	Total tariff activities				798			493
	Margin activities				80			72
			Total		878			565

(1)

Revenues and cost of sales and operations include intersegment amounts.

(2)

General and administrative ("G&A") expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)

Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period.

        Total average daily volumes transported were approximately 878,000 barrels per day and 565,000 barrels per day for the nine months ended September 30, 2003 and 2002, respectively. As discussed above, we have completed a number of acquisitions during 2003 and 2002 that have impacted the

34

results of operations herein. The following table reflects our total average daily volumes from our tariff activities by year of acquisition from their date of acquisition for comparison purposes:

		Nine months ended September 30,
		2003	2002
		(thousands of barrels per day)
Tariff activities(1)
	2003 acquisitions	58	—
	2002 acquisitions	348	103
	All other pipeline systems	392	390
	Total tariff activities average daily volumes	798	493

(1)

Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period.

        Average daily volumes from our tariff activities were approximately 798,000 barrels per day compared to approximately 493,000 barrels per day for the prior year period. Approximately 303,000 barrels per day of the increase in the current year period is due to volumes transported on the pipelines acquired in 2003 and 2002, including approximately 244,000 on the assets acquired in the Shell acquisition. Volumes transported on all other pipeline systems increased approximately 2,000 barrels per day to 392,000 barrels per day. This increase included approximately 5,000 barrels per day more on our Canadian pipelines in the first nine months of 2003 than in the first nine months of 2002, and approximately 7,000 barrels per day more on our West Texas Gathering System. Offsetting these increases is an approximate 5,000 barrel per day decrease in our All American tariff volumes attributable to a decline in OCS production and various smaller decreases on other systems. The increase in our Canadian volumes primarily resulted from the completion of capital expansion projects during 2002 that allowed for additional volumes. Concurrently, our West Texas Gathering System has benefited from the shutdown of the Rancho pipeline and also from temporary refinery problems that have diverted crude oil barrels from other systems.

        Total revenues from our pipeline operations were approximately $489.1 million and $334.1 million for the nine months ended September 30, 2003 and 2002, respectively. The increase in revenues was primarily related to our margin activities, which increased by approximately $114.8 million in the 2003 period. This increase was primarily related to higher average prices on our margin activity on our San Joaquin Valley gathering system in the 2003 period as compared to the 2002 period, but was also positively impacted by higher volumes on our buy/sell arrangements in the current period. However, this business is a margin business and although revenues and cost of sales are impacted by the absolute level of crude oil prices, this factor had a limited impact on gross margin.

35

        Revenues from our tariff activities increased approximately $40.2 million. The following table reflects our revenues from our tariff activities by year of acquisition for comparison purposes:

		Nine months ended September 30,
		2003		2002
		(in millions)
Tariff activities revenues(1)
	2003 acquisitions	$	8.0	$	—
	2002 acquisitions		40.7		10.6
	All other pipeline systems		63.7		61.6
	Total tariff activities	$	112.4	$	72.2

(1)

Revenues include intersegment amounts.

        Total revenues from our tariff activities were approximately $112.4 million and $72.2 million for the nine months ended September 30, 2003 and 2002, respectively. The increase in 2003 of $40.2 million is predominately related to the inclusion of revenues from the businesses acquired in 2003 and an increase in revenues from the pipeline systems acquired in the Shell acquisition as they have been included for nine months of 2003 versus two months of 2002. Revenues from all other pipeline systems increased approximately $2.1 million to $63.7 million for the nine months ended September 30, 2003. Canadian revenues increased approximately $2.5 million primarily due to higher volumes and tariffs in the current period coupled with a $2.2 million favorable exchange rate impact. The favorable exchange rate impact resulted from a decrease in the Canadian to U.S. dollar exchange rate to an average rate of 1.43 for the nine months ended September 30, 2003, from an average rate of 1.57 for the nine months ended September 30, 2002. Revenues from our West Texas Gathering System also increased approximately $1.1 million. These increases were partially offset by decreased revenues from various of our U.S. pipeline systems, including a $2.1 million decrease on our All American system on which we receive the highest per barrel tariffs among our pipeline operations.

        As a result of these factors, pipeline operations gross margin (excluding depreciation) increased 38% to approximately $83.5 million for the nine months ended September 30, 2003, from $60.3 million for the prior year period, an increase of approximately $23.2 million. Incorporated in this increase is approximately $1.4 million from a more favorable Canadian dollar to U.S. dollar exchange rate in the 2003 period as compared to the 2002 period. Such results also incorporate an increase in operating expenses to $42.7 million in the 2003 period from $25.9 million in the 2002 period. This increase includes $0.4 million related to the accrual made for the probable vesting of unit grants under our LTIP. The remaining increase is predominately related to our continued growth, primarily from acquisitions, coupled with higher utility costs and regulatory compliance activities.

        General and administrative expenses increased approximately $6.4 million between comparable periods, partially as a result of a $2.6 million accrual related to the probable vesting of unit grants under our LTIP and our continued growth, primarily from acquisitions. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has increased in the 2003 period as our pipeline operations have grown. Including the impact of the items discussed above, gross profit (excluding depreciation) was approximately $67.2 million in the first nine months of 2003, an increase of 33% as compared to the $50.4 million reported for the nine months ended September 30, 2002. Incorporated in this increase is approximately $1.3 million from a more favorable Canadian dollar to U.S. dollar exchange rate in the 2003 period as compared to the 2002 period.

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Gathering, Marketing, Terminalling and Storage Operations

        The following table sets forth our operating results from our Gathering, Marketing, Terminalling and Storage Operations segment for the periods indicated:

			Nine months ended September 30,
			2003			2002
Operating Results (in millions)(1)
	Revenues		$	8,594.8		$	5,554.6
	Cost of sales and operations (excluding depreciation and LTIP accrual)			(8,513.8	)		(5,490.5	)
	LTIP accrual—operations			(1.0	)		—
	Gross Margin (excluding depreciation)		$	80.0		$	64.1
	General and administrative expenses (excluding LTIP accrual)(2)			(23.7	)		(23.5	)
	LTIP accrual—general and administrative			(3.4	)		—
	Gross Profit (excluding depreciation)		$	52.9		$	40.6
	Noncash SFAS 133 impact(3)		$	(1.7	)	$	(2.1	)
	Maintenance capital		$	0.7		$	1.3
Average Daily Volumes (thousands of barrels per day except as otherwise noted)(4)
	Crude oil lease gathering			430			406
	Crude oil bulk purchases			84			69
		Total		514			475
	LPG sales			43			40
	Cushing Terminal throughput			196			87
	Storage leased to third parties, monthly average volumes			1,124			1,103

(1)

Revenues and cost of sales and operations include intersegment amounts.

(2)

General and administrative ("G&A") expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on the business activities that existed at that time. The proportional allocations by segment require judgment by management and will continue to be based on the business activities that exist during each period.

(3)

Amounts related to SFAS 133 are included in revenues, gross margin (excluding depreciation) and gross profit (excluding depreciation).

(4)

Volumes associated with acquisitions represent weighted averaged daily amounts for the number of days we actually owned the assets over the total days in the period.

        During the first nine months of 2003, market conditions were extremely volatile as a confluence of several events caused the NYMEX benchmark price of crude oil to fluctuate widely, with periods of steep backwardation throughout the first eight months of 2003 (See Outlook—Other for additional discussion regarding our expectations for the remainder of the year). The NYMEX benchmark price of crude oil ranged from as high as $39.99 per barrel to as low as $25.04 per barrel during this nine month period. Additionally, results from the first quarter of 2003 were further enhanced by increased sales and higher margins in our LPG activities resulting from cold weather throughout the U.S. and Canada.

        Because of the overall counter-cyclical balance of our assets and the flexibility embedded in our business strategy, the benefit we received from the periods of pronounced backwardation, volatile market conditions and increased tankage available to our gathering and marketing business in the first nine months of 2003 more than offset the adverse impact of reduced storage activities. In contrast,

37

during a substantial portion of the first nine months of 2002, the crude oil market was in contango, which enhances the economics of storing crude oil and increases demand for storage services from third parties, but is generally disadvantageous for our gathering and marketing activities.

        As a result of these factors, our gross margin (excluding depreciation) increased approximately $15.9 million or 25% to $80.0 million as compared to $64.1 million in the first nine months of 2002. Included in these results is a $1.7 million non-cash, mark-to-market loss pursuant to SFAS 133 in the first nine months of 2003 and a $2.1 million, SFAS 133 non-cash mark-to-market loss in the comparable 2002 period. The impact of SFAS 133 adjustments accounted for $0.4 million or approximately 3% of the increase in gross margin (excluding depreciation). Also included in gross margin (excluding depreciation) is a favorable impact of $1.9 million resulting from a decrease in the average Canadian to U.S. dollar exchange rate to 1.43 in the 2003 period from 1.57 in the 2002 period.

        These results incorporate an increase in operating expenses to $57.6 million in the 2003 period from $49.0 million in the 2002 period related to our continued growth, primarily from acquisitions, coupled with increased regulatory compliance activities and higher fuel costs. Operating expenses for the 2003 period also include $1.0 million related to the accrual for our LTIP.

        General and administrative expenses increased approximately $3.6 million to $27.1 million in the current year period. Included in general and administrative expenses for the nine months ended September 30, 2003, is $3.4 million related to the accrual for the probable vesting of unit grants under our LTIP. General and administrative expenses also reflect a general decrease in the percentage of non-direct costs allocated to the Gathering, Marketing, Terminalling and Storage Operations segment as our pipeline operations have grown. Gross profit (excluding depreciation) was approximately $52.9 million in the first nine months of 2003, an increase of $12.3 million from the nine months ended September 30, 2002. This increase incorporates the favorable impacts of approximately $1.2 million resulting from a decrease in the Canadian dollar to U.S. dollar exchange rate in the 2003 period as compared to the 2002 period and a $0.4 million favorable difference in the impact of the SFAS 133 adjustments. Both of these items were partially offset by accruals for the probable vesting of unit grants under our LTIP totaling $4.4 million, as discussed above.

        In addition to market conditions and our hedging activities, the primary drivers of the performance of our Gathering, Marketing, Terminalling and Storage Operations segment are crude oil lease gathered volumes and LPG sales volumes. Crude oil bulk purchase volumes are not considered a driver as they are primarily used to enhance margins of lease gathered barrels. Gross profit per barrel (excluding depreciation) for the nine months ended September 30, 2003 and 2002, was $0.41 per barrel and $0.33 per barrel, respectively.

        For the nine months ended September 30, 2003, we gathered from producers, using our assets or third-party assets, approximately 430,000 barrels of crude oil per day, an increase of 6% over similar activities in the first nine months of 2002. In addition, we purchased in bulk, primarily at major trading locations, approximately 84,000 barrels of crude oil per day in the 2003 period and approximately 69,000 barrels per day in the 2002 period. Storage leased to third parties at our Cushing facility was flat over the two periods. Cushing Terminal throughput volumes averaged approximately 196,000 barrels per day and 87,000 barrels per day for the nine months ended September 30, 2003 and 2002, respectively. Also during the first nine months of 2003 and 2002, we marketed approximately 43,000 and 40,000 barrels per day of LPG, respectively.

        Revenues from our Gathering, Marketing, Terminalling and Storage Operations were approximately $8.6 billion and $5.6 billion for the nine months ended September 30, 2003 and 2002, respectively. Revenues and cost of sales and operations (excluding depreciation) for 2003 were primarily impacted by higher average prices and increased crude oil lease gathering volumes in the 2003 period as compared to the 2002 period. The average NYMEX price for crude oil was $31.03 per barrel and $25.39 per barrel for the first nine months of 2003 and 2002, respectively.

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Other Expenses

Depreciation and Amortization

        Depreciation and amortization expense related to operations was approximately $29.5 million for the nine months ended September 30, 2003, compared to $19.7 million for the same period of 2002. Approximately $5.6 million of the increase is associated with the assets acquired in the Shell acquisition. The remainder of the increase is primarily related to the completion of various capital expansion projects and other acquisitions. Depreciation and amortization expense related to general and administrative items increased approximately $1.3 million to $4.7 million in the first nine months of 2003 from the first nine months of 2002 because of higher debt issue costs, technology expenditures and various other smaller items. Debt amortization costs included in depreciation and amortization expense were $3.0 million and $2.5 million in the first nine months of 2003 and 2002, respectively. The increase was because of higher debt issue costs related to the amendment of our credit facilities during 2002 and the sale of senior unsecured notes in September 2002.

Interest Expense

        Interest expense increased approximately $6.3 million to $26.5 million for the nine months ended September 30, 2003, from $20.2 million for the comparable 2002 period. The increase was primarily related to an increase in the average debt balance during the 2003 period to approximately $524.7 million from approximately $422.0 million in the 2002 period, which resulted in additional interest expense of approximately $4.7 million. The higher average debt balance was primarily due to the portion of the Shell acquisition that was not financed with equity. This debt was outstanding for the entire period in 2003 versus only a portion of the period in 2002. In addition, increased commitment and other fees coupled with lower capitalized interest resulted in approximately $2.2 million of the increase in the 2003 period. Our weighted average interest rate decreased slightly during the first nine months of 2003 to 6.0% versus 6.2% for the nine months ended September 30, 2002, which decreased our interest expense by approximately $0.6 million. Although the interest rate change was slight, it was the net result of various factors that included an increase in the amount of fixed rate, long-term debt, long-term interest rate hedges and declining short-term interest rates. In mid-September 2002, we issued $200 million of ten-year bonds bearing a fixed interest rate of 7.75%. In the fourth quarter of 2002 and the first quarter of 2003, the company entered into hedging arrangements to lock in interest rates on approximately $50 million of its floating rate debt. In addition, the average three-month LIBOR rate declined from approximately 1.9% during the first nine months of 2002 to approximately 1.2% during the first nine months of 2003. The net impact of these factors, increased commitment fees and changes in average debt balances decreased the average interest rate by 0.2%.

Outlook

        On October 29, 2003, we furnished information in an amended current report on Form 8-K/A containing management's guidance for operating and financial performance for the fourth quarter of 2003 and preliminary guidance for 2004, including a discussion of the significant factors and assumptions management considered in preparing our guidance, as well as a discussion of factors that could cause actual results to differ materially from results anticipated in the forward-looking statements. Information that is "furnished" in a Form 8-K is typically not included in a periodic report such as this quarterly report. As a result, the projections, assumptions and risk factors discussed in our 8-K/A furnished on October 29 are not incorporated by reference in this report.

        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.

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Crude Oil Inventory

        We value our crude oil inventory at the lower of cost or market, with cost determined using an average cost method. At September 30, 2003 we had approximately 574,000 barrels of inventory classified as unhedged operating inventory at a weighted average cost of $25.81 per barrel. The lower of cost or market method requires a write down of inventory to the market price at the end of a period in which our weighted average cost exceeds the market price. This method does not allow a write up of the inventory if the market price subsequently increases. We did not have an adjustment in this period. However, future fluctuations in crude oil prices could result in a period end lower of cost or market adjustment.

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. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. We are currently in advanced negotiations for a crude oil pipeline and storage acquisition that is complementary to our existing asset base. We have signed a letter of intent with the seller and are in advanced negotiations with respect to a definitive purchase and sale agreement. If consummated under current terms, the purchase price is expected to be approximately $50 million. Since 1998, we have completed numerous acquisitions for an aggregate purchase price of approximately $1.3 billion. We can give you no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us. In connection with these activities, we routinely incur third party costs, which are capitalized and deferred pending final outcome of the transaction. Deferred costs associated with successful transactions are capitalized as part of the transaction, while deferred costs associated with unsuccessful transactions are expensed at the time of such final determination. At September 30, 2003, the amount of costs deferred pending final outcome was $0.3 million.

Vesting of Unit Grants Under Long-Term Incentive Plan

        As of September 30, 2003, there were grants covering approximately one million restricted units outstanding under our LTIP. Restricted unit grants become eligible to vest in the same proportion as the conversion of our outstanding subordinated units into common units, subject to any additional vesting requirements.

        The subordination period (as defined in the partnership agreement) for the 10,029,619 outstanding subordinated units will end if certain financial tests are met for three consecutive, non-overlapping four-quarter periods (the "testing period"). See Note 6 to the Consolidated Financial Statements. We are now in the testing period and, in connection with the payment of the quarterly distribution in November 2003, 25% of the outstanding subordinated units will convert into common units. In conjunction with this conversion, approximately 35,000 restricted units vest, and a 90-day period will commence for approximately 220,000 additional restricted units that will not have any remaining vesting requirements except that the holder must continue employment with the Partnership for the remainder of the 90-day period.

        Probable Vesting.    Under generally accepted accounting principles, we are required to recognize an expense when it is considered probable that the financial tests for conversion of subordinated units and required distribution levels will be met and that restricted unit grants will vest. At September 30, 2003 we concluded that the vesting of approximately 255,000 restricted units was probable and thus accrued

40

approximately $7.4 million of compensation expense based upon an estimated market price of $30.05 per unit (the unit price as of September 30, 2003), our share of employment taxes and other related costs. Under the LTIP, we may satisfy our obligations using a combination of cash, the issuance of new units and delivery of units purchased in the open market. Approximately $2.8 million of the $7.4 million accrued at September 30, 2003 is related to units granted to senior management of the partnership and will be settled almost exclusively with the delivery of units, net of taxes. We anticipate that in November 2003, to satisfy the vesting of those restricted units that vest substantially contemporaneously with the conversion of subordinated units, we will issue approximately 18,000 common units after netting for taxes and paying cash in lieu of a portion of the vested units. For those restricted units that require passage of time to vest, the 90-day period will expire and final vesting will occur in February 2004. We estimate we will issue approximately 100,000 common units in the first quarter of 2004 in connection with this probable vesting.

        Potential Vesting.    At the current distribution level of $2.20 per unit, assuming that the additional subordination conversion tests are met as of December 31, 2003, approximately 580,000 additional units will vest in connection with the payment of the quarterly distribution in February 2004. If at December 31, 2003, it is considered probable that this distribution level and tests will be met, the costs associated with the vesting of these additional units will be estimated and accrued in the fourth quarter of 2003. At a distribution level of $2.30 to $2.49, the number of additional units that would vest would increase by approximately 87,000. At a distribution level at or above $2.50, the number of additional units that would vest would increase by approximately 87,000. In all cases, vesting is subject to any applicable continuing employment requirements.

        Subject to providing those holding less than a certain number of restricted units the option to receive cash, we are currently planning to issue units to satisfy the majority of restricted unit obligations that vest in connection with the conversion of subordinated units. If all conditions to vesting are met, we currently project the issuance of units (approximately 100,000 common units in connection with the probable vesting and approximately 239,000 common units in connection with the potential vesting) in the first half of 2004 to satisfy such obligations. Obligations satisfied by the issuance of units will result in a non-cash compensation expense. Purchase of units would result in a cash charge to compensation expense. In addition, the "company match" portion of payroll taxes, plus the value of any units withheld for taxes, will result in a cash charge. The aggregate amount of the potential charge to expense will be determined by the unit price on the date vesting occurs multiplied by the number of units, plus our share of associated employment taxes. The amount of the potential charge is subject to various factors, including the unit price on the date vesting occurs, and thus is not known at this time. As mentioned above, we have accrued approximately $7.4 million as of September 30, 2003 in connection with the probable vesting. At the current distribution level and based on an assumed market price of $30.05 per unit (the unit price as of September 30, 2003), the aggregate additional charge that would be triggered by the potential vesting (that is, if we determine it is probable that the additional units will vest) would be approximately $21 million, of which approximately $17 million would be accrued as of December 31, 2003 (although payment and issuance of units would not occur until the first and second quarters of 2004). Approximately $6.1 million of the potential charge is related to units granted to senior management of the partnership and will be settled almost exclusively with the delivery of units, net of taxes. We currently estimate that approximately one-third of the aggregate potential charge of $21 million will be settled with the delivery of units and the remainder in cash.

Contingent Equity Issuance

        In connection with the CANPET acquisition in July 2001, approximately $26.5 million Canadian dollars of the purchase price, payable in common units, was deferred subject to various performance objectives being met. If these objectives are met as of December 31, 2003, the deferred amount is payable on April 30, 2004. The number of common units issued in satisfaction of the deferred payment

41

will depend upon the average trading price of our common units for a ten-day trading period prior to the payment date and the Canadian and U.S. dollar exchange rate on the payment date. In addition, an amount will be paid equivalent to the distributions that would have been paid on the common units had they been outstanding since the acquisition was consummated. At our option, the deferred payment may be paid in cash rather than the issuance of units. We believe that it is probable that the objectives will be met and the deferred amount will be paid in April 2004, however, it is not determinable beyond a reasonable doubt. Assuming the tests are met as of December 31, 2003, and the entire obligation is satisfied with common units, based on the foreign exchange rate and the ten-day average unit price in effect at September 30, 2003, (1.35 Canadian to U.S. dollar exchange rate and $30.36 per unit price) approximately 650,000 units would be issued.

Basin Expansion

        We are currently evaluating a potential expansion of a segment of the Basin Pipeline System that extends from Colorado City to Cushing, Oklahoma. At times, the pipeline has operated at levels that are close to its current maximum throughput and we would like to be positioned to handle increased volumes if market conditions warrant. We estimate the expected expansion investment to be approximately $1.5 million and would expect higher incremental operating costs as we would have to activate pump stations that are currently idled. However, we can give no assurances that our volumes transported would increase as a result of this expansion.

OCS production

        In early October, Plains Exploration and Production announced that they had received all of the necessary permits to develop a portion of the Rocky Point structure that is accessible from the Point Arguello platforms and it appears that they will commence drilling activities in the first quarter of 2004. Such drilling activities, if successful, are not expected to have a significant impact on pipeline shipments on our All American Pipeline system in 2004. However, such incremental drilling activity, if successful, could lead to increased volumes on our All American Pipeline System in 2005 and beyond. However, we can give no assurances that our volumes transported would increase as a result of this drilling activity.

Pipeline Rate Regulation

        Our interstate common carrier pipeline operations are subject to rate regulation by the Federal Energy Regulatory Commission ("FERC") under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines, which includes crude oil, as well as refined product and petrochemical pipelines, be just and reasonable and non-discriminatory. The Energy Policy Act of 1992 deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of the Energy Policy Act or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable under the Interstate Commerce Act. Generally, complaints against such "grandfathered" rates may only be pursued if the complainant can show that a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate or that a provision of the tariff is unduly discriminatory or preferential. In a FERC proceeding involving SFPP, L.P., certain shippers are challenging grandfathered rates on the basis of changed circumstances since the passage of the Energy Policy Act. The ultimate disposition of this challenge may define "substantial change" in such a way as to make grandfathered rates more vulnerable to challenge than has historically been the case. We are uncertain what effect, if any, an unfavorable determination in the FERC proceeding might have on our grandfathered tariffs.

        On June 26, 2003, the FERC issued a Notice of Proposed Rulemaking that, if adopted, would impose substantial new reporting burdens on oil pipeline companies. Numerous regulated entities and

42

industry groups have commented on the proposal, and we cannot predict what the final provisions of the rulemaking might include, nor the impact the final rule would have on us.

Other

        The following factors are likely to have a negative influence on our operating and financial results for the fourth quarter of 2003:

•

In August, a blackout of electrical systems occurred in the Midwestern and Northeastern portions of the United States and Eastern Canada. Our pipelines and facilities were not directly impacted by the blackout and there was minimal adverse impact on our operations in the third quarter. However, as a result of related refinery shutdowns that caused crude oil pipelines within these regions to run slower than normal and the related impact on differentials within our Canadian operations, we currently anticipate that the indirect impact of the blackout may reduce fourth quarter earnings and cash flow by approximately $1 million.



•

We are also expecting an increased level of operating expenses associated with a pipeline spill that occurred in October of 2003 in a remote area of Mississippi. On October 13, 2003, a raised pipeline crossing was struck and severed by a falling pine tree, which caused approximately 350 barrels of oil to escape the pipeline. We estimate that the costs related to containing the spill and clean up and recovery operations will increase operating expenses by approximately $1 million in the fourth quarter of 2003.



•

In addition, the steep backwardation in the crude oil forward market (see Results of Operations—Gathering, Marketing, Terminalling and Storage Operations) that existed for most of the first eight months of the year weakened in September and we expect these weaker market conditions to continue for the remainder of the year. As a result, market conditions for the gathering and marketing business are not expected to be as strong in the fourth quarter of 2003 as they were for the first three quarters of 2003.

Liquidity and Capital Resources

Liquidity

        Cash generated from operations and our credit facilities are our primary sources of liquidity. At September 30, 2003, we had a working capital deficit of approximately $65.3 million, approximately $441.9 million (net of $8.0 million to refinance term loan maturities due in the next twelve months) of availability under our revolving credit facility and $125.7 million of availability under the letter of credit and hedged inventory facility. Usage of the credit facilities is subject to compliance with covenants. We believe we are currently in compliance with all covenants.

        We funded the purchase of the acquisitions completed in the first nine months of the year with funds drawn on our revolving credit facilities and available cash on hand. In September 2003, we completed a public offering of 3,250,000 common units priced at $30.91 per unit. Net proceeds from the offering, including our general partner's proportionate capital contribution and expenses associated with the offering, were approximately $98.0 million and were used to pay down our revolving credit facilities and term loan. In March 2003, we completed a public offering of 2,645,000 common units priced at $24.80 per unit. Net proceeds from the offering, including our general partner's proportionate capital contribution and expenses associated with the offering, were approximately $63.9 million and were used to pay down our revolving credit facilities.

        On October 27, 2003, we announced that we intend to replace our existing senior secured credit facilities with new senior unsecured credit facilities totaling $750 million and a $200 million, 364-day uncommitted facility for the purchase of hedged crude oil. The new senior unsecured facility will be

43

comprised of a $455 million, 4-year revolving credit facility, a $170 million 364-day facility (with a 5-year term out option), and a $125 million, 364-day revolving credit facility.

        In conjunction with this transaction, we anticipate a non-cash charge of approximately $3.3 million attributable to a loss on the early extinguishment of debt. This expected loss consists of unamortized debt issue costs expected to be written off as a result of the completion of the new credit facility. However, the actual amount of the charge will depend on the final provisions and lenders of the new facility. Although we anticipate closing the refinancing in the fourth quarter of 2003, we can give no assurances that we will successfully consummate the transaction.

        The following table reflects our long-term debt obligations as of September 30, 2003 (in millions):

Calendar Year		Payment
2004		$	8.0
2005			8.1
2006			76.0
2007			162.0
2008			—
Thereafter			200.0
	Total(1)	$	454.1

(1)

Includes unamortized discount on 7.75% senior notes of approximately $0.4 million.

        We believe that we have sufficient liquid assets, cash from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely effect our cash flow. A material decrease in our cash flows would likely produce a corollary adverse effect on our borrowing capacity.

Cash Flows

		Nine Months Ended September 30,
		2003			2002
		(in millions)
Cash provided by (used in):
	Operating activities	$	195.7		$	127.4
	Investing activities		(144.8	)		(349.8	)
	Financing activities		(51.0	)		223.3

        Operating Activities.    Net cash provided by operating activities for the nine months ended September 30, 2003 was $195.7 million as compared to $127.4 million in the 2002 period. Cash provided by operating activities in the current year period consisted primarily of (i) net income of $59.6 million, (ii) depreciation and amortization of $34.2 million, (iii) a change in derivative fair value related to SFAS 133 of $1.7 million and (iv) net changes in assets and liabilities of approximately $100.1 million. Cash provided by operating activities in the prior year period consisted primarily of (i) net income of $47.5 million, (ii) depreciation and amortization of $23.1 million, (iii) a change in derivative fair value related to SFAS 133 of $2.1 million and (iv) net changes in assets and liabilities of approximately $54.7 million. The net changes in assets and liabilities are generally the result of the timing of cash receipts related to sales and cash disbursements related to purchases, inventory and other expenses. Inventory purchases and sales are accounted for as a use and source, respectively, of cash provided by operating activities. Accordingly, during periods of significant inventory builds or

44

draws, cash provided by operating activities will fluctuate significantly. Significant inventory activity is typically associated with periods when the market is transitioning into or out of contango, a market condition where prompt month crude oil prices trade at a discount to crude oil prices in one or more future months, and periods following acquisitions or expansion activities where the partnership builds working inventory to operate the expanded asset base.

        Investing Activities.    Net cash used in investing activities in 2003 includes an approximately $17.0 million deposit made for the ArkLaTex acquisition and an aggregate $82.9 million paid for acquisitions completed in the first half of 2003 and before and approximately $52.2 million for additions to property and equipment. These additions consist of $18.2 million related to the construction of crude oil gathering and transmission lines in West Texas and $34.0 million related to other capital projects. Net cash used in investing activities in 2002 includes $309.5 million related to our Shell acquisition, $14.3 million for other acquisitions, and $27.4 million of capital expenditures primarily for the Cushing expansion and other capital projects.

        Financing Activities.    Cash used in financing activities in 2003 consisted of (i) approximately $161.9 million of proceeds from the issuance of common units used to pay down outstanding balances on the revolving credit facility and Senior secured term B loan, (ii) $89.3 million of distributions paid to unitholders and the general partner, (iii) $43.0 million of principal repayments of our term loans, (iv) net repayments on our long-term revolving credit facilities of $13.1 million, and (v) net short-term debt repayments of $67.3 million primarily from the proceeds of inventory sales. Cash provided by financing activities in 2002 consisted primarily of (i) $199.6 million of proceeds from the issuance of senior unsecured notes, (ii) $145.3 million of proceeds from the issuance of common units, (iii) net repayments on our long-term revolving credit facilities of $42.3 million, (iv) $3.0 million of payments on our term loans, (v) $71.6 million of distributions paid to unitholders and the general partner, and (vi) a $5.4 million payment related to our financing arrangements.

Universal Shelf

        We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue from time to time up to an aggregate of $700 million of debt or equity securities. At September 30, 2003, we have approximately $255 million remaining under this registration statement.

Contingencies

        Litigation.    We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

        Indemnities.    In November, 2002, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others ("FIN 45"). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We are party to various contracts entered into in the ordinary course of business that contain indemnity provisions pursuant to which we indemnify the counterparties against various expenses. Our indemnity obligations are contingent upon the occurrence of events or circumstances specified in the contracts. No such events or circumstances have occurred at this time, and we do not consider our liability under such indemnity provisions, individually or in the aggregate, to be material to our financial position or results of operations.

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        Operational Hazards and Insurance.    Pipelines, terminals or other facilities 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. Since the Partnership and its predecessors commenced midstream crude oil activities in the early 1990s, we have maintained insurance of various types and varying levels of coverage that we considered adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. However, such insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. Over the last several years, our operations have expanded significantly, with total assets increasing approximately 200% since the end of 1998. At the same time that the scale and scope of our business activities have expanded, the breadth and depth of the available insurance markets have contracted. Notwithstanding what we believe is a favorable claims history, the overall cost of such insurance as well as the deductibles and overall retention levels that we maintain have increased. This trend was reinforced in connection with the renewal of our insurance program in June 2003. Absent a material favorable change in available insurance markets, this trend of rising insurance-related costs is expected to continue as we continue to grow and expand. As a result, it is anticipated that we will elect to self insure more activities against certain of these operating hazards.

        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. We believe that our reserve for environmental liabilities is adequate. However, 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.    Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets (including our nation's pipeline infrastructure) may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. We have instituted security measures and procedures in conformity with Department of Transportation ("DOT") guidance. We will institute, as appropriate, additional security measures or procedures indicated by the DOT or the Transportation Safety Administration (an agency of the Department of Homeland Security, which is in the transitional phase of assuming responsibility from the DOT). We cannot assure you that these or any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not.

        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 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 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.

Industry Credit Markets and Accounts Receivable

        Throughout the latter part of 2001 and all of 2002, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and extreme financial distress at several large, diversified energy companies, the

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energy industry has been especially impacted by these developments. Accordingly, we are exposed to an increased level of direct and indirect counterparty credit and performance risk.

        The majority of our credit extensions relate to our gathering and marketing activities that can generally be described as high volume and low margin activities. In our credit approval process, we make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit or advance cash payments. At September 30, 2003, we had received approximately $39.5 million of advance cash payments from third parties to mitigate credit risk. These proceeds reduced our working capital requirements and were used to reduce long-term borrowings.

Recent Accounting Pronouncements

        We continuously monitor and revise our accounting policies as our business and relevant accounting literature change. For further discussion of new accounting rules, see Item 1. Consolidated Financial Statements—Note 11 "Recent Accounting Pronouncements."

Forward-Looking Statements and Associated Risks

        All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," "intend" and "forecast," and similar expressions and statements regarding our business strategy, plans and objectives for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

•

abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on the All American Pipeline;



•

declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers;



•

the availability of adequate supplies of and demand for crude oil in the areas in which we operate;



•

the effects of competition;



•

the success of our risk management activities;



•

the impact of crude oil price fluctuations;



•

the availability (or lack thereof) of acquisition or combination opportunities;



•

successful integration and future performance of acquired assets;



•

continued creditworthiness of, and performance by, our counterparties;



•

conversion (or non-conversion) of our subordinated units into common units;



•

completion of the refinancing of our credit facilities;



•

our levels of indebtedness and our ability to receive credit on satisfactory terms;



•

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;

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•

the impact of current and future laws and governmental regulations;



•

the currency exchange rate of the Canadian dollar;



•

environmental liabilities that are not covered by an indemnity or insurance;



•

fluctuations in the debt and equity markets, 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 or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

        The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risks included in Item 7A. in our 2002 Form 10-K. There have not been any material changes in that information other than those discussed below.

        As of September 30, 2003 and December 31, 2002 the fair value of our crude oil futures contracts was approximately $30.6 million and $0.6 million respectively. A 10% price decrease would result in a decrease in fair value of $12.0 million and $4.3 million at September 30, 2003 and December 31, 2002, respectively.

        During the first quarter of 2003, we converted a $50.0 million treasury lock into a 10-year LIBOR based swap that becomes effective in March 2004, contemporaneously with the expiration of an existing $50.0 million LIBOR based swap. At September 30, 2003, the fair value of our interest rate risk hedging instruments was a liability of approximately $10.5 million with $0.7 million maturing in 2004, $4.5 million in 2006 and $5.3 million in 2014.

        As of September 30, 2003, the fair value of our currency exchange rate risk hedging instruments was a liability of approximately $4.0 million with $0.3 million maturing during 2003 and the remainder in 2006.

Item 4. CONTROLS AND PROCEDURES

        We maintain written "disclosure controls and procedures," which we refer to as our "DCP." The purpose of our DCP is to 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. Our DCP is incremental to our system of internal accounting controls designed to comply with the requirements of Section 13(b)(2) of the Exchange Act.

        Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP, as of September 30, 2003, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Management (including our Chief Executive Officer and Chief Financial Officer) has evaluated the effectiveness of the design and operation of our DCP as of September 30, 2003, 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.

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        In addition to the information concerning our DCP, we are required to disclose certain changes in our internal control over financial reporting. There was no change in our internal control over financial reporting that occurred during the third quarter and that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

        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

        We, in the ordinary course of business, are a claimant and/or a defendant in various legal proceedings. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.

Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

        None

Item 3. DEFAULTS UPON SENIOR SECURITIES

        None

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        None

Item 5. OTHER INFORMATION

        None

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Item 6. EXHIBITS AND REPORTS ON FORM 8-K

        A. Exhibits

3.1	Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC dated June 8, 2001, as amended by the First Amendment dated September 16, 2003
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.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350

        B. Reports on Form 8-K.

        A current report on Form 8-K/A was furnished on October 29, 2003, to correct certain information in the Form 8-K furnished on October 28, 2003.

        A current report on Form 8-K was furnished on October 28, 2003, in connection with disclosure of fourth quarter 2003 projections and earnings guidance and preliminary guidance for certain aspects of financial performance for 2004.

        A current report on Form 8-K was furnished on October 7, 2003, in connection with the disclosure of our presentation at Independent Petroleum Association of America's 2003 Oil & Gas Investment Symposium West.

        A current report on Form 8-K was furnished on September 24, 2003, in connection with the disclosure of our presentation at Herold's 12^th Annual Pacesetters Energy Conference.

        A current report on Form 8-K was furnished on September 16, 2003, in connection with the disclosure of our presentation at the RBC Capital Markets 2003 North American Energy and Power Conference.

        A current report on Form 8-K was filed on September 10, 2003, including as an exhibit an underwriting agreement with Citigroup Global Markets Inc., Lehman Brothers Inc., UBS Securities LLC, A.G. Edwards & Sons, Inc., Wachovia Capital Markets, LLC and RBC Dain Rauscher Inc. in connection with the sale by the Partnership of 3,250,000 common units of the Partnership.

        A current report on Form 8-K was furnished on September 8, 2003, in connection with disclosure of our planned sale of common units pursuant to an effective shelf registration on Form S-3 previously filed with the Securities and Exchange Commission.

        A current report on Form 8-K was filed on August 21, 2003, including as an exhibit the unaudited balance sheet of Plains AAP, L.P. as of June 30, 2003.

        A current report on Form 8-K was furnished on August 5, 2003, in connection with disclosure of our presentation at the Enercom 8th Annual Oil & Gas Conference.

        A current report on Form 8-K was furnished on July 29, 2003, in connection with disclosure of third quarter and full year 2003 projections and earnings guidance and preliminary guidance for certain aspects of financial performance for 2004.

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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: November 7, 2003	By:	/s/ GREG L. ARMSTRONG Greg L. Armstrong, Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC (Principal Executive Officer)
Date: November 7, 2003	By:	/s/ PHIL KRAMER Phil Kramer, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

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