PLAINS ALL AMERICAN PIPELINE LP - 10-Q Quarterly Report

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2002

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

Delaware		76-0582150
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

333 Clay Street, Suite 1600

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 646-4100

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

At November 4, 2002, there were outstanding 38,240,939 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, 2002, and December 31, 2001		3
Consolidated Statements of Operations:
For the three and nine months ended September 30, 2002 and 2001		4
Consolidated Statements of Cash Flows:
For the nine months ended September 30, 2002 and 2001		5
Consolidated Statement of Partners’ Capital:
For the nine months ended September 30, 2002		6
Consolidated Statements of Comprehensive Income:
For the three and nine months ended September 30, 2002 and 2001		7
Consolidated Statement of Changes in Accumulated Other Comprehensive Income:
For the nine months ended September 30, 2002		7
Notes to Consolidated Financial Statements		8

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS		30

Item 4. CONTROLS AND PROCEDURES		30

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		31

Item 2. Changes in Securities and Use of Proceeds		31

Item 3. Defaults Upon Senior Securities		31

Item 4. Submission of Matters to a Vote of Security Holders		31

Item 5. Other Information		31

Item 6. Exhibits and Reports on Form 8-K		31

Signatures		33

Certification of Principal Executive Officer		34

Certification of Principal Financial Officer		35

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, 2002			December 31, 2001
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4,306		$	3,511
Accounts receivable and other current assets		496,857			365,697
Inventory		81,189			188,874

Total current assets		582,352			558,082

PROPERTY AND EQUIPMENT		1,012,814			653,050
Less allowance for depreciation and amortization		(67,900	)		(48,131	)

		944,914			604,919

OTHER ASSETS
Pipeline linefill		51,416			57,367
Other, net		52,808			40,883

		104,224			98,250

	$	1,631,490		$	1,261,251


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and other current liabilities	$	468,988		$	386,993
Due to related parties		25,580			13,685
Short-term debt		105,577			101,482

Total current liabilities		600,145			502,160

LONG-TERM LIABILITIES
Long-term debt under credit facilities		309,453			354,677
Senior notes, net of unamortized discount of $400		199,600			—
Other long-term liabilities and deferred credits		4,317			1,617

Total liabilities		1,113,515			858,454

COMMITMENTS AND CONTINGENCIES (NOTE 8)

PARTNERS’ CAPITAL
Common unitholders (38,240,939 and 31,915,939 units outstanding at September 30, 2002, and December 31, 2001, respectively)		529,488			408,562
Class B common unitholders (1,307,190 units outstanding at each date )		18,621			19,534
Subordinated unitholders (10,029,619 units outstanding at each date)		(45,900	)		(38,891	)
General partner		15,766			13,592

Total partners’ capital		517,975			402,797

	$	1,631,490		$	1,261,251

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

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,
	2002			2001			2002			2001
	(unaudited)
REVENUES	$	2,344,089		$	2,191,310		$	5,874,759		$	5,298,051
COST OF SALES AND OPERATIONS		2,299,823			2,151,666			5,750,398			5,189,288

Gross Margin		44,266			39,644			124,361			108,763

EXPENSES
General and administrative		11,512			10,297			33,389			34,327
Depreciation and amortization		8,981			6,402			23,125			17,575

Total expenses		20,493			16,699			56,514			51,902

OPERATING INCOME		23,773			22,945			67,847			56,861
Interest expense		(7,368	)		(7,775	)		(20,175	)		(22,482	)
Interest and other income (expense)		(88	)		(9	)		(123	)		356

Income before cumulative effect of accounting change		16,317			15,161			47,549			34,735
Cumulative effect of accounting change		—			—			—			508

NET INCOME	$	16,317		$	15,161		$	47,549		$	35,243

NET INCOME—LIMITED PARTNERS	$	15,159		$	14,536		$	44,515		$	34,019

NET INCOME—GENERAL PARTNER	$	1,158		$	625		$	3,034		$	1,224

BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income before cumulative effect of accounting change	$	0.33		$	0.38		$	1.01		$	0.93
Cumulative effect of accounting change		—			—			—			0.01

Net income	$	0.33		$	0.38		$	1.01		$	0.94

WEIGHTED AVERAGE UNITS OUTSTANDING		46,027			38,353			44,188			36,156

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Nine Months Ended September 30,
	2002			2001
	(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	47,549		$	35,243
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		23,125			17,575
Cumulative effect of accounting change		—			(508	)
Change in derivative fair value		2,130			(774	)
Noncash compensation expense		—			5,741
Change in assets and liabilities, net of assets acquired and liabilities assumed:
Accounts receivable and other current assets		(129,930	)		(189,490	)
Inventory		104,664			(8,037	)
Accounts payable and other current liabilities		67,954			149,408
Due to related parties		11,895			(3,679	)

Net cash provided by operating activities		127,387			5,479

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid in connection with acquisitions		(323,786	)		(209,264	)
Additions to property and equipment		(27,445	)		(13,804	)
Proceeds from sales of assets		1,390			1,808

Net cash used in investing activities		(349,841	)		(221,260	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		1,122,346			1,655,475
Proceeds from short-term debt		411,350			258,655
Principal payments of long-term debt		(1,167,659	)		(1,537,935	)
Principal payments of short-term debt		(410,598	)		(202,555	)
Cash paid in connection with financing arrangements		(11,721	)		(10,649	)
Proceeds from the issuance of common units		151,671			106,209
Proceeds from the issuance of senior unsecured notes		199,600			—
Distributions paid to unitholders and general partner		(71,642	)		(52,981	)

Net cash provided by financing activities		223,347			216,219

Effect of translation adjustment on cash		(98	)		—

Net increase in cash and cash equivalents		795			438
Cash and cash equivalents, beginning of period		3,511			3,426

Cash and cash equivalents, end of period	$	4,306		$	3,864

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands)

	Common Units				Class B Common Units				Subordinated Units				General Partner Amount			Total Partners’ Capital Amount
	Units	Amount			Units	Amount			Units	Amount			General Partner Amount			Total Partners’ Capital Amount
	(unaudited)
Balance at December 31, 2001	31,916	$	408,562		1,307	$	19,534		10,030	$	(38,891	)	$	13,592		$	402,797
Issuance of common units	6,325		142,013		—		—		—		—			3,033			145,046
Distributions	—		(50,267	)	—		(2,059	)	—		(15,797	)		(3,519	)		(71,642	)
Accumulated other comprehensive income	—		(4,030	)	—		(158	)	—		(1,213	)		(374	)		(5,775	)
Net income	—		33,210		—		1,304		—		10,001			3,034			47,549

Balance at September 30, 2002	38,241	$	529,488		1,307	$	18,621		10,030	$	(45,900	)	$	15,766		$	517,975

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

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,
	2002			2001			2002			2001
	(unaudited)
Net income	$	16,317		$	15,161		$	47,549		$	35,243
Other comprehensive income		(16,723	)		(5,398	)		(5,775	)		(11,236	)

Total comprehensive income	$	(406	)	$	9,763		$	41,774		$	24,007

Statement of Changes in Accumulated Other Comprehensive Income

	Net Deferred Loss on Derivative Instruments			Currency Translation Adjustments			Total
	(unaudited)
Beginning balance at December 31, 2001	$	(4,740	)	$	(8,002	)	$	(12,742	)
Current year activity
Reclassification adjustments for settled contracts		3,185			—			3,185
Changes in fair value of outstanding hedge positions		(9,531	)		—			(9,531	)
Currency translation adjustment		—			571			571

Total current year activity		(6,346	)		571			(5,775	)

Ending balance at September 30, 2002	$	(11,086	)	$	(7,431	)	$	(18,517	)

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

We are a Delaware limited partnership formed in September of 1998. On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the midstream crude oil business and assets of Plains Resources Inc. and its midstream subsidiaries. The term “Partnership” herein refers to Plains All American Pipeline, L.P. and its affiliated operating partnerships. Our operations are conducted directly and indirectly through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil pipeline transportation as well as gathering, marketing, terminalling and storage of crude oil and liquefied petroleum gas (“LPG”). We own an extensive network in the United States and Canada of pipeline transportation, storage and gathering assets in key oil producing basins and at major market hubs. Our operations are conducted primarily in Texas, California, Oklahoma, Louisiana and the Canadian provinces of Alberta and Saskatchewan.

The accompanying financial statements and related notes present our consolidated financial position as of September 30, 2002, and December 31, 2001, the results of our operations for the three and nine months ended September 30, 2002 and 2001, cash flows for the nine months ended September 30, 2002 and 2001, changes in partners’ capital for the nine months ended September 30, 2002, total comprehensive income for the three and nine months ended September 30, 2002 and 2001, and changes in accumulated other comprehensive income for the nine months ended September 30, 2002. The financial statements have been prepared in accordance with the instructions to 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 and nine months ended September 30, 2002, should not be taken as indicative of the results to be expected for the full year. The interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2001 Annual Report on Form 10-K.

Note 2—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, foreign exchange rates, NYMEX and over-the-counter positions, and physical volumes, grades, locations and delivery schedules to ensure that our hedging activities are implemented in accordance with such policies. 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.

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 (see Note 6 for a discussion of the mitigation of credit risk). In accordance with Statement of Financial

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities,” these derivative instruments are recognized in the balance sheet or earnings at their fair values. Changes in fair value are included in the current period for (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 amount included in earnings related to our commodity price risk activities for the nine months ended September 30, 2002, was a $2.1 million loss. The effective portion of changes in fair values of derivatives that qualify as cash flow hedges is recorded in Other Comprehensive Income (“OCI”). At September 30, 2002, there was a $0.4 million loss deferred in OCI related to our commodity price risk activities. The majority of our commodity price risk derivative instruments qualify for hedge accounting as cash flow hedges and thus the corresponding changes in fair value for the effective portion of the hedge are recognized in revenues or cost of sales and operations in the periods during which the underlying physical transactions occur. We have determined that our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133.

Controlled Trading Program

As a result of production and delivery variances associated with our lease purchase activities, from time to time we experience net unbalanced positions. 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. This activity is monitored independently by our risk management function and must take place within predefined limits and authorizations. We record this activity at fair value in accordance with Emerging Issues Task Force (“EITF”) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (see Note 9). EITF 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in fair value recorded net in revenues. Although there were no open positions under this program at September 30, 2002, the realized earnings impact related to these derivatives for the nine months ended September 30, 2002, was a loss of $0.3 million.

Interest Rate Risk Hedging

We also utilize interest rate swaps and collars to hedge interest obligations on specific debt issuances. At September 30, 2002, we had interest rate swaps for an aggregate notional principal amount of $150.0 million. These instruments are based on LIBOR rates and provide for a LIBOR rate of 3.6% for a $100.0 million notional principal amount expiring September 2003, and a LIBOR rate of 4.3% for a $50.0 million notional principal amount expiring March 2004. Interest on the actual debt is based on LIBOR plus a margin. In anticipation of the issuance of our 7.75% senior notes due October 2012 and potential subsequent add-on thereto, in July 2002, we entered into a treasury lock on a $100 million principal amount with an effective interest rate of 4.51% and maturing on November 22, 2002. A treasury lock is a financial derivative instrument that enables the company to lock in the U.S. Treasury Note rate. In October 2002, the LIBOR swaps expiring in September 2003 and half of the treasury lock were consolidated into a $50 million LIBOR swap maturing in October 2006 at a rate of 5.05%. All of the financial instruments utilized are placed with large creditworthy financial institutions. 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, 2002, there was a $10.9 million loss deferred in OCI related to our interest rate risk activities.

Currency Exchange Rate Risk Hedging

Since substantially all 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. At September 30, 2002, we

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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 2002 and 2003 (based on a Canadian-U.S. dollar exchange rate of 1.54). At September 30, 2002, we also had a cross currency swap contract for an aggregate notional principal amount of $24.8 million, effectively converting this amount of our $99.0 million senior secured term loan (25% of the total) from U.S. dollars to $38.3 million of Canadian dollar debt (based on a Canadian-U.S. dollar exchange rate of 1.55). The terms of this contract mirror the term loan, matching the amortization schedule and final maturity in May 2006. Additionally, at September 30, 2002, $2.0 million of our long-term debt was denominated in Canadian dollars ($3.1 million CAD based on a Canadian-U.S. dollar exchange rate of 1.59). All of these financial instruments are placed with large creditworthy financial institutions. The forward exchange contracts and forward extra option contracts qualify for hedge accounting as cash flow hedges and the cross currency swaps qualify for hedge accounting as fair value hedges, both in accordance with SFAS 133. Such derivative activity resulted in a gain of $0.2 million deferred in OCI related to our currency exchange rate cash flow hedges. The earnings impact related to our currency exchange rate fair value hedges was nominal.

Summary of Financial Impact

The following is a summary of the financial impact of the derivative instruments and hedging activities discussed above. The September 30, 2002, balance sheet includes a $11.1 million unrealized loss in OCI, related assets of $6.3 million ($4.7 million current) and related liabilities of $18.8 million ($16.0 million current). Revenues for the nine months ended September 30, 2002, included a noncash loss of $2.1 million ($1.4 million noncash loss net of the reversal of the prior period fair value adjustment related to contracts that settled during the current period). Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet.

As of September 30, 2002, the total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. During the nine months ended September 30, 2002, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Based on the amounts deferred to OCI at September 30, 2002, a loss of $9.5 million will be reclassified to earnings in the next twelve months and the remainder by 2004. 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.

Note 3—Acquisitions

On August 1, 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 8.7 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”). The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since that date (see Note 7). The primary assets included in the transaction are interests in the Basin Pipeline System, the Permian Basin Gathering System and the Rancho Pipeline System. These assets complement our existing asset infrastructure in West Texas and represent a transportation link to Cushing, Oklahoma, where we are a provider of storage and terminalling services. The total purchase price of $322.7 million consisted of (i) $304.0 million in cash, which was borrowed under our revolving credit facility, (ii) approximately $9.1 million related to the settlement of pre-existing accounts receivable and inventory balances and (iii) approximately $9.6 million of estimated transaction and closing costs. The entire purchase price was allocated to Property and Equipment. We are in the process of evaluating certain estimates made in the purchase price allocation; thus, the allocation is subject to refinement.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

The following unaudited pro forma data is presented to show pro forma revenues, net income and basic and diluted net income per limited partner unit for the Partnership as if the Shell acquisition had occurred on January 1, 2001 (in millions, except for per unit amounts):

	Nine Months Ended September 30,
	2002		2001
Revenues	$	5,900.9	$	5,342.5

Income before cumulative effect of accounting change	$	46.9	$	37.3

Net income	$	46.9	$	37.9

Basic and diluted income before cumulative effect of accounting change per limited partner unit	$	0.99	$	1.00

Basic and diluted net income per limited partner unit	$	0.99	$	1.01

Note 4—Credit Facilities and Long-term Debt

During September 2002, we completed the sale of $200 million of 7.75% senior notes due in October 2012. The notes were issued by Plains All American Pipeline, L.P. and a 100% owned finance subsidiary (neither of which have independent assets or operations) at a discount of $0.4 million, resulting in an effective interest rate of 7.78%. Interest payments are due on April 15 and October 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries which are minor.

As amended in July 2002 and giving effect to the third quarter capital raising activities, our credit facilities consist of a $350.0 million senior secured letter of credit and hedged inventory facility (with current lender commitments totaling $200.0 million), and a $747.0 million senior secured revolving credit and term loan facility, each of which is secured by substantially all of our assets. The terms of our credit facilities enable us to expand the size of the letter of credit and hedged inventory facility from $200.0 million to $350.0 million without additional approval from existing lenders. The revolving credit and term loan facility consists of a $420.0 million domestic revolving facility (with a $10.0 million letter of credit sublimit), a $30.0 million Canadian revolving facility (with a $5.0 million letter of credit sublimit), a $99.0 million term loan, and a $198.0 million term B loan.

The facilities have final maturities as follows:

•

as to the $350.0 million senior secured letter of credit and hedged inventory facility and the aggregate $450.0 million domestic and Canadian revolver portions, in April 2005;

•

as to the $99.0 million term loan, in May 2006; and

•

as to the $198.0 million term B loan, in September 2007.

The financial covenants of these credit facilities require us to maintain:

•

a current ratio (as defined) of at least 1.0 to 1.0;

•

a debt coverage ratio which will not be greater than: 5.25 to 1.0 on unsecured debt and 4.0 to 1.0 on secured debt;

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

•

an interest coverage ratio that is not less than 2.75 to 1.0; and

•

a debt to capital ratio of not greater than 0.7 to 1.0 through March 30, 2003, and 0.65 to 1.0 at any time thereafter.

The combined domestic and Canadian revolving facility had approximately $12 million outstanding at September 30, 2002. In addition, we have classified $9 million of term loan payments due in 2003 as long term due to our intent and ability to refinance those maturities using the revolving facility.

For covenant compliance purposes, letters of credit and borrowings under the letter of credit and hedged inventory facility are excluded when calculating the debt coverage ratio. We are currently in compliance with the covenants contained in our credit agreements.

The amended facility permits us to issue up to an aggregate $400 million of senior unsecured debt having a maturity beyond the final maturity of the existing credit facility, and provides a mechanism to reduce the amount of the domestic revolving credit facility. The foregoing description of the credit facility incorporates the reduction associated with the $200 million senior note offering completed in September 2002. Depending on the amount of additional senior indebtedness incurred, the domestic revolving credit facility will be reduced by an amount equating to 40% to 63% of any incremental indebtedness up to the aggregate $400 million limitation.

Note 5—Partners’ Capital and Distributions

In August 2002, we completed a public offering of 6,325,000 common units for $23.50 per unit. The offering resulted in cash proceeds of approximately $148.6 million from the sale of the units and approximately $3.0 million from our general partner’s proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $6.6 million. Net proceeds of approximately $145.0 million were used to reduce outstanding borrowings under the domestic revolving credit facility.

On October 24, 2002, we declared a cash distribution of $0.5375 per unit on our outstanding common units, Class B common units and subordinated units. The distribution is payable on November 14, 2002, to unitholders of record on November 4, 2002, for the period July 1, 2002, through September 30, 2002. The total distribution to be paid is approximately $28.2 million, with approximately $21.2 million to be paid to our common unitholders, $5.4 million to be paid to our subordinated unitholders and $1.6 million to be paid to our general partner for its general partner and incentive distribution interests. The distribution is in excess of the minimum quarterly distribution specified in the Partnership Agreement.

On July 23, 2002, we declared a cash distribution of $0.5375 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid on August 14, 2002, to unitholders of record on August 5, 2002, for the period April 1, 2002, through June 30, 2002. The total distribution paid was approximately $24.6 million, with approximately $17.8 million paid to our common unitholders, $5.4 million paid to our subordinated unitholders and $1.4 million paid to our general partner for its general partner and incentive distribution interests. The distribution was in excess of the minimum quarterly distribution specified in the Partnership Agreement.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Note 6—Recent Disruptions in Industry Credit Markets

As a result of business failures, revelations of material misrepresentations and related financial restatements by several large, well-known companies in various industries over the last year, 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 troubling disclosures by several large, diversified energy companies, the energy industry has been especially impacted by these developments, with the rating agencies downgrading a number of large, energy-related companies. Accordingly, in this environment we are exposed to an increased level of direct and indirect counterparty credit and performance risk.

The majority of our credit extensions and therefore our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. In transacting business with our counterparties, we must determine the amount, if any, of open credit lines to extend to our counterparties and the form and amount of financial performance assurances we may require. The vast majority of such accounts receivable settle monthly and any collection delays generally involve discrepancies or disputes as to the appropriate price, volume or quality of crude oil delivered or exchanged and associated billing delays. Of our $357.6 million aggregate receivables balance included in current assets at December 31, 2001, approximately $330.9 million, or 93%, were less than sixty days past the scheduled invoice date. Of our $483.7 million aggregate receivables balance included in current assets at September 30, 2002, approximately $474.0 million, or 98%, were less than sixty days past the scheduled invoice date.

We have modified our credit arrangements with certain counterparties that have been adversely affected by these recent events, but a large portion of the balances more than sixty days past the invoice date, along with approximately $10.8 million of net receivables classified as long-term, are associated with an ongoing effort to bring substantially all balances to within sixty days of scheduled invoice date. In certain cases, this effort involves reconciling and resolving certain discrepancies, generally related to pricing, volumes, quality or crude oil exchange imbalances, and the majority of these receivables are related to monthly periods leading up to and immediately following the disclosure of our unauthorized trading losses in late 1999. Following that disclosure, a significant number of our suppliers and trading partners temporarily reduced or eliminated our open credit and demanded payments or withheld payments due us before disputed amounts or discrepancies associated with exchange imbalances, pricing issues and quality adjustments were reconciled in accordance with customary industry practices. Because these matters also arose in the midst of various software systems conversions and acquisition integration activities, our effort to resolve outstanding claims and discrepancies has included reprocessing and integrating historical information on numerous software platforms. We have made significant progress to date in this effort and intend to substantially complete this project by the end of 2002 and, based on the work performed to date and the scope of the remaining work to be performed, we believe these prior period balances are collectible or subject to offsets and consider our reserves adequate. However, in the event our counterparties experience an unanticipated deterioration in their credit-worthiness, any addition to existing reserves or write-offs in excess of such reserves would result in a noncash charge to earnings. We do not believe any such charge would have a material effect on our cash flow or liquidity.

Note 7—Operating Segments

Our operations consist of two operating segments: (1) Pipeline Operations—engages in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; (2) Gathering, Marketing, Terminalling and Storage Operations—engages in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on gross margin and gross profit (gross margin less general and administrative expenses).

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

	Pipeline		Gathering, Marketing, Terminalling & Storage		Total
	(in millions)
Three Months Ended September 30, 2002
Revenues:
External customers	$	123.4	$	2,220.7	$	2,344.1
Intersegment (a)		7.0		—		7.0

Total revenues	$	130.4	$	2,220.7	$	2,351.1

Gross margin (b)	$	23.0	$	21.3	$	44.3
General and administrative expenses (c)		3.2		8.3		11.5

Gross profit (d)	$	19.8	$	13.0	$	32.8

Maintenance capital	$	0.5	$	0.7	$	1.2


Three Months Ended September 30, 2001
Revenues:
External customers	$	88.8	$	2,102.5	$	2,191.3
Intersegment (a)		4.5		—		4.5

Total revenues	$	93.3	$	2,102.5	$	2,195.8

Gross margin (b)	$	16.1	$	23.5	$	39.6
General and administrative expenses (c)		2.9		7.4		10.3

Gross profit (d)	$	13.2	$	16.1	$	29.3

Maintenance capital	$	0.4	$	0.2	$	0.6


Nine Months Ended September 30, 2002
Revenues:
External customers	$	320.2	$	5,554.6	$	5,874.8
Intersegment (a)		13.9		—		13.9

Total revenues	$	334.1	$	5,554.6	$	5,888.7

Gross margin (b)	$	60.3	$	64.1	$	124.4
General and administrative expenses (c)		9.3		24.1		33.4

Gross profit (d)	$	51.0	$	40.0	$	91.0

Maintenance capital	$	2.7	$	1.3	$	4.0


Nine Months Ended September 30, 2001
Revenues:
External customers	$	268.7	$	5,029.4	$	5,298.1
Intersegment (a)		12.9		—		12.9

Total revenues	$	281.6	$	5,029.4	$	5,311.0

Gross margin (b)	$	48.3	$	60.5	$	108.8
General and administrative expenses (c)		8.3		20.3		28.6

Gross profit (d)	$	40.0	$	40.2	$	80.2

Maintenance capital	$	0.5	$	2.4	$	2.9

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

(a)

Intersegment sales are based on published tariff rates.

(b)

Gross margin is calculated as revenues less cost of sales and operations expenses.

(c)

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 exist at that time. For comparison purposes, we have reclassified G&A expenses by segment for all periods presented to conform to the refined presentation used in the third quarter of 2002. The proportional allocations by segment will continue to be based on the business activities that exist during each period.

(d)

Gross profit is calculated as gross margin less general and administrative expenses, excluding noncash compensation expense as it is not allocated to the reportable segments.

Note 8—Contingencies

Export License Matter. In our marketing and gathering activities, we import and export crude oil from and to Canada. Our exports of crude oil are licensed under two export licenses from the Bureau of Industry and Security (the “BIS”) of the U.S. Department of Commerce. We have determined that we may have exceeded the quantity of crude oil exports authorized by the licenses. Export of crude oil in excess of the authorized amounts is a violation of the Export Administration Regulations (“EAR”). On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. Upon completion of our internal inquiry, we will voluntarily submit additional information to the BIS. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of these potential violations.

Other. A pipeline, terminal 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. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers all of our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The events of September 11, 2001, and their overall effect on the insurance industry has had an adverse impact on availability and cost of coverage. Due to these events, insurers have excluded acts of terrorism and sabotage from our insurance policies. On certain of our key assets, we purchased a separate insurance policy for acts of terrorism and sabotage.

Since the terrorist attacks, the United States Government has issued numerous warnings that energy assets (including our nation’s pipeline infrastructure) may be a future target of terrorist organizations. These developments expose our operations and assets to increased risks. 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 that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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

Note 9—Recent Accounting Pronouncements

In October 2002, the EITF reached consensus on certain issues in EITF Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under Issues No. 98-10 and 00-17.” The consensus reached included i) rescinding EITF 98-10 and ii) the requirement that mark-to-market gains and losses on trading contracts (whether realized or unrealized and whether financially or physically settled) be shown net in the income statement. The EITF provided guidance that, beginning on October 25, 2002, all new contracts that would have been accounted for under EITF 98-10 should no longer be marked-to-market through earnings unless such contracts fall within the scope of SFAS 133. All of the contracts that we have accounted for under EITF 98-10 fall within the scope of SFAS 133 and therefore will continue to be marked-to-market through earnings under the provisions of that rule. Therefore, we do not believe that the adoption of this rule will have a material effect on either our financial position, results of operations or cash flows.

In June 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS 146 “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred rather than at the date of the exit plan. This Statement is effective for exit or disposal activities that are initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on either our financial position, results of operations or cash flows.

In April 2002, the FASB issued SFAS 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS 145 rescinds, updates, clarifies and simplifies existing accounting pronouncements. Among other things, SFAS 145 rescinds SFAS 4, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. Under SFAS 145, the criteria in Accounting Principles Board No. 30 will now be used to classify those gains and losses. The adoption of this and the remaining provisions of SFAS 145 did not have a material effect on our financial position or results of operations. However, any future extinguishments of debt may impact income from continuing operations.

In June 2001, the FASB issued SFAS 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 an asset retirement cost 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. We will adopt the statement effective January 1, 2003, as required. The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle. Although we are in the process of evaluating the impact of adoption, we cannot reasonably estimate the effect of the adoption of this statement on either our financial position, results of operations or cash flows at this time.

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

We are a Delaware limited partnership formed in September of 1998. On November 23, 1998, we completed our initial public offering and the transactions whereby we became the successor to the midstream crude oil business and assets of Plains Resources Inc. and its midstream subsidiaries. Our operations are conducted directly and indirectly through Plains Marketing, L.P., All American Pipeline, L.P. and Plains Marketing Canada, L.P. We are engaged in interstate and intrastate crude oil pipeline transportation as well as gathering, marketing, terminalling and storage of crude oil and liquefied petroleum gas (“LPG”). We own an extensive network in the United States and Canada of pipeline transportation, storage and gathering assets in key oil producing basins and at major market hubs. Our operations are conducted primarily in Texas, California, Oklahoma, Louisiana and the Canadian provinces of Alberta and Saskatchewan and consist of two operating segments: (i) Pipeline Operations and (ii) Gathering, Marketing, Terminalling and Storage Operations. We evaluate segment performance based on gross margin and gross profit (gross margin less general and administrative expenses).

The following acquisitions impact the comparability of the 2002 and 2001 periods as noted in the discussion below:

•

On August 1, 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 8.7 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, (which we refer to collectively as the “Shell acquisition”). The results of operations from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since that date. The primary assets included in the transaction are interests in the Basin Pipeline System, the Permian Basin Gathering System and the Rancho Pipeline System. These assets complement our existing asset infrastructure in West Texas and represent a transportation link to Cushing, Oklahoma, where we are a provider of storage and terminalling services. The total purchase price of $322.7 million consisted of (i) $304.0 million in cash, which was borrowed under our revolving credit facility, (ii) approximately $9.1 million related to the settlement of pre-existing accounts receivable and inventory balances and (iii) approximately $9.6 million of estimated transaction and closing costs.

•

In 2001, we acquired substantially all of the Canadian crude oil pipeline, gathering, marketing, terminalling and storage assets of Murphy Oil Company Ltd. and the assets of CANPET Energy Group Inc., a Calgary-based Canadian crude oil and liquefied petroleum gas marketing company, together the “Canadian acquisitions.” The Canadian acquisitions were effective April 1, 2001, and July 1, 2001, respectively.

Results of Operations

The following table reconciles our reported net income to our net income before unusual or nonrecurring items and the impact of SFAS 133:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002		2001			2002		2001
	(millions)					(millions)
Reported net income	$	16.3	$	15.2		$	47.5	$	35.2
Noncash compensation expense		—		—			—		5.7
Noncash cumulative effect of accounting change (1)		—		—			—		(0.5	)
Noncash SFAS 133 adjustment		0.4		(0.7	)		2.1		(0.8	)

Net income before unusual or nonrecurring items and the impact of SFAS 133	$	16.7	$	14.5		$	49.6	$	39.6

(1)

Related to the adoption of SFAS 133 on January 1, 2001.

For the three months ended September 30, 2002, we reported net income of $16.3 million on total revenues of $2.3 billion compared to net income for the same period in 2001 of $15.2 million on total revenues of $2.2 billion. For the nine months ended September 30, 2002, we reported net income of $47.5 million on total revenues of $5.9 billion compared to net income for the same period in 2001 of $35.2 million of total revenues of $5.3 billion. When evaluating our results, we exclude the 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 which 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.

Pipeline Operations

We own and operate over 5,500 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a fee, third-party leases of pipeline capacity, barrel exchanges and buy/sell arrangements. We also use our pipelines in our merchant activities conducted under our gathering and marketing business. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The gross margin 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 from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2002		2001		2002		2001
Operating Results (in millions):
Revenues (including intersegment)	$	130.4	$	93.3	$	334.1	$	281.6

Gross margin	$	23.0	$	16.1	$	60.3	$	48.3
General & administrative expenses		3.2		2.9		9.3		8.3

Gross profit	$	19.8	$	13.2	$	51.0	$	40.0

Average Daily Volumes (thousands of barrels per day) (1):
Tariff activities
All American		68		68		65		68
Basin		157		—		53		—
Other domestic		256		139		186		148
Canada (2)		201		191		186		118
Margin activities		71		53		72		58

Total		753		451		562		392

(1)

Total volumes transported on assets acquired during the period have been divided by the total number of days in the period to get a daily average.

(2)

2001 volume information is adjusted for consistency of comparison with 2002 presentation.

Pipeline Operations for the Three Months Ended September 30, 2002 and 2001

Average daily volumes on our pipelines during the third quarter of this year were approximately 753,000 barrels per day compared to 451,000 barrels per day for the prior year quarter, which was an increase of approximately 302,000 barrels per day. Approximately 298,000 barrels per day of the increase in the third quarter of 2002 resulted from the acquisition of various businesses during 2002 and late 2001, including approximately 266,000 barrels per day related to the businesses acquired in the Shell acquisition.

Total revenues from our pipeline operations were approximately $130.4 million and $93.3 million for the three months ended September 30, 2002 and 2001, respectively. Excluding the revenues of $11.1 million from businesses acquired during 2002 and late 2001, revenues from our pipeline operations would have been approximately $119.3 million for the three months ended September 30, 2002. That is an increase of approximately $26.0 million over the comparable 2001 revenues. Of this increase, approximately $25.1 million relates to our merchant activities on our San Joaquin Valley gathering system. This increase was related to both increased volumes and higher average prices on our buy/sell arrangements in 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.

Gross margin from pipeline operations increased to approximately $23.0 million for the quarter ended September 30, 2002, from $16.1 million for the prior year quarter, an increase of $6.9 million primarily related to the acquisition of various businesses during 2002 and late 2001.

General and administrative expense (“G&A”) related to pipeline operations was $3.2 million for the quarter ended September 30, 2002, compared to $2.9 million for the third quarter of 2001. The increase in 2002 is primarily due to expenses associated with our Canadian acquisitions.

Pipeline Operations for the Nine Months Ended September 30, 2002 and 2001

Average daily volumes on our pipelines during the nine months ended September 30, 2002, were approximately 562,000 barrels per day compared to an average of 392,000 barrels per day for the prior year period, which was an increase of approximately 170,000 barrels per day. Approximately 119,000 barrels per day of the increase resulted from the acquisition of various businesses in 2002 and late 2001, including an average of approximately 89,000 barrels per day related to the businesses acquired in the Shell acquisition. The remainder of the increase was primarily related to the inclusion of the average daily volumes from the pipeline assets included in the Canadian acquisitions for all of the 2002 period compared to only six months during the 2001 period.

Total revenues from our pipeline operations were approximately $334.1 million and $281.6 million for the nine months ended September 30, 2002 and 2001, respectively. Excluding revenues of approximately $12.7 million from various businesses acquired during 2002 and late 2001, revenues from our pipeline operations would have been approximately $321.4 million for the nine months ended September 30, 2002. This reflects an increase of approximately $39.8 million over the comparable 2001 revenues. Of this increase, approximately $33.3 million relates to our merchant activities on our SJV gathering system. The increase was related to both increased volumes and higher average prices on our buy/sell arrangements in 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. The remainder of the increase in revenues is primarily related to the inclusion of the results of operations from the pipeline assets included in the Canadian acquisitions for all of the 2002 period compared to only six months during the 2001 period.

Gross margin from pipeline operations increased to approximately $60.3 million for the nine months ended September 30, 2002, from $48.3 million for the prior year period, an increase of $12 million. The increase primarily related to the acquisition of various businesses during 2002 and late 2001 and the inclusion of the

results of operations from the pipeline assets included in the Canadian acquisitions for all of the 2002 period compared to only six months during the 2001 period.

G&A expense related to pipeline operations was $9.3 million for the nine months ended September 30, 2002, compared to $8.3 million for the first nine months of 2001. The increase in 2002 is primarily due to expenses associated with our Canadian acquisitions which were acquired in April and July of 2001.

Gathering, Marketing, Terminalling and Storage Operations

Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased barrels plus the sale of additional barrels exchanged through buy/sell arrangements entered into to enhance the margins of the gathered and bulk-purchased crude oil. Gross margin from our gathering and marketing activities is dependent on our ability to sell crude oil at a price in excess of our aggregate cost. These operations are margin businesses, and are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil 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 21.3 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 the largest crude oil market hub 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.” Gross margin from terminalling and storage activities is dependent on the throughput volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. We also use our storage tanks to counter cyclically balance our gathering and marketing operations and to execute different hedging strategies to stabilize margins and reduce the negative impact of crude oil market volatility.

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,				Nine Months Ended September 30,
	2002		2001		2002		2001
Operating Results (in millions):
Revenues	$	2,220.7	$	2,102.5	$	5,554.6	$	5,029.4

Gross margin	$	21.3	$	23.5	$	64.1	$	60.5
General & administrative expenses		8.3		7.4		24.1		20.3

Gross profit	$	13.0	$	16.1	$	40.0	$	40.2

Average Daily Volumes (thousands of barrels per day) (1)(2):
Lease gathering		408		391		406		334
Bulk purchases		85		55		74		39

Total		493		446		480		373

Terminal throughput		123		97		92		103

Storage leased to third parties, monthly average volumes		811		2,672		1,323		2,337

(1)

Total volumes attributable to acquisitions during the period have been divided by the total number of days in the period to get a daily average.

(2)

2001 volume information is adjusted for consistency of comparison with 2002 presentation.

Gathering, Marketing, Terminalling and Storage Operations for the Three Months Ended September 30, 2002 and 2001

For the three months ended September 30, 2002, we gathered from producers, using our assets or third-party assets, approximately 408,000 barrels of crude oil per day. In addition, we purchased in bulk, primarily at major trading locations, approximately 85,000 barrels of crude oil per day. Storage leased to third parties decreased to an average of 0.8 million barrels per day from an average of 2.7 million barrels per day in the prior year quarter as we used an increased amount of our capacity for our own account due to contango market activities in the current year period. A contango market exists when oil prices for future deliveries are higher than current prices thereby making it profitable to store crude oil for future delivery. Terminal throughput volumes averaged approximately 123,000 barrels per day and 97,000 barrels per day for the quarter ended September 30, 2002 and 2001, respectively.

Revenues from our gathering, marketing, terminalling and storage operations were approximately $2.2 billion and $2.1 billion for the quarter ended September 30, 2002 and 2001, respectively. Revenues for 2002 were impacted both by increased volumes over the comparative prior year quarter as well as higher average prices. The average NYMEX price for crude oil was $28.27 per barrel and $26.78 per barrel for the third quarter of 2002 and 2001, respectively.

Gross margin from gathering, marketing, terminalling and storage activities was approximately $21.3 million for the quarter ended September 30, 2002, compared to $23.5 million in the prior year quarter. Excluding the impact of the noncash fair value adjustments related to SFAS 133, gross margin for this segment would have been approximately $21.7 million for the quarter ended September 30, 2002, compared to $22.8 million in the prior year quarter. The 2002 results were negatively impacted by hurricanes Isidore and Lili that caused the temporary shut-in of oil production in the Gulf of Mexico during the third quarter.

G&A related to gathering, marketing, terminalling and storage operations was $8.3 million for the quarter ended September 30, 2002, compared to $7.4 million for the third quarter of 2001. The increase in 2002 is primarily due to expenses associated with our Canadian acquisitions, partially offset by a decrease in other G&A expenses related to the domestic operations.

Gathering, Marketing, Terminalling and Storage Operations for the Nine Months Ended September 30, 2002 and 2001

For the nine months ended September 30, 2002, we gathered from producers, using our assets or third-party assets, approximately 406,000 barrels of crude oil per day. In addition, we purchased in bulk, primarily at major trading locations, approximately 74,000 barrels of crude oil per day. Storage leased to third parties decreased to an average of 1.3 million barrels per day from an average of 2.3 million barrels per day in the prior year period as we used an increased amount of our capacity for our own account due to contango market activities in the current year period. Terminal throughput volumes averaged approximately 92,000 barrels per day and 103,000 barrels per day for the nine months ended September 30, 2002 and 2001, respectively.

Revenues from our gathering, marketing, terminalling and storage operations were approximately $5.6 billion and $5.0 billion for the nine months ended September 30, 2002 and 2001, respectively. Revenues from our Canadian operations were approximately $1.1 billion for the 2002 period, which was an increase of approximately $0.6 billion over the prior year period. The increase was partially related to the inclusion of the Canadian acquisitions for all of 2002 compared to a portion of 2001. This had the impact of increasing volumes by approximately 84,000 barrels per day. Domestic gathering volumes increased an average of approximately 22,000 barrels per day in the 2002 period from the comparable 2001 period, but the increased volumes were offset by decreased prices resulting in relatively flat revenues from our domestic operations. The average NYMEX price for crude oil was $25.39 per barrel and $27.86 per barrel for the nine months ended September 30, 2002 and 2001, respectively.

Gross margin from gathering, marketing, terminalling and storage activities was approximately $64.1 million for the nine months ended September 30, 2002, compared to $60.5 million in the prior year period. Excluding the impact of the noncash fair value adjustments related to SFAS 133, gross margin for this segment would have been approximately $66.2 million for the nine months ended September 30, 2002, compared to $59.7 million in the prior year period. The increase is partially related to the inclusion of the businesses acquired in the Canadian acquisitions for all of 2002 compared to the portion of 2001 subsequent to acquisition. In addition, higher domestic volumes contributed to higher gross margin in 2002.

G&A expense related to gathering, marketing, terminalling and storage operations was $24.1 million for the nine months ended September 30, 2002, compared to $20.3 million for the 2001 period. The increase in 2002 is primarily due to expenses associated with our Canadian acquisitions, partially offset by a decrease in other G&A expenses related to the domestic operations.

Other Expenses

Depreciation and Amortization

Depreciation and amortization expense was $9.0 million for the quarter ended September 30, 2002, compared to $6.4 million for the same period of 2001. Approximately $1.6 million of the increase is associated with the assets acquired in the Shell acquisition. For the nine months ended September 30, 2002, depreciation and amortization expense increased to $23.1 million, an increase of $5.5 million from the $17.6 million reported in the 2001 period. Approximately $4.0 million of the increase is attributable to our acquisitions completed in 2002, as well as those completed in 2001, but not outstanding the entire period. The remainder of the increase for both periods is related to an increase in debt issue costs related to the amendment of our credit facilities during 2002 and late 2001, the sale of the senior unsecured notes in September 2002, and the completion of various capital expansion projects.

Interest Expense

Interest expense decreased to $7.4 million for the quarter ended September 30, 2002, from $7.8 million for the comparative 2001 period. For the nine months ended September 30, 2002, interest expense decreased to $20.2 million from $22.5 million for the comparative 2001 period. The decreases are due to the capitalization of interest and lower interest rates somewhat offset by higher average debt balances and increased commitment fees. Interest in the amount of $0.2 million and $0.6 million for the quarter and nine months, respectively was capitalized in conjunction with the construction of our Cushing terminal expansion. The lower interest rates are due to a decrease in LIBOR and prime rates in the current year. During the third quarter of 2001, we issued $200 million of term B notes. Proceeds were used to reduce borrowings under the revolver. As such, our commitment fees on our revolver increased, as they are based on unused availability. The overall increased debt balance in 2002 is related to the Shell acquisition in August 2002.

Outlook

On October 29, 2002, we furnished Item 9 information in a current report on Form 8-K, containing guidance for operating and financial performance for the fourth quarter of 2002 and updated selected preliminary guidance information for 2003.

Acquisition Activities. Consistent with our acquisition strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstream crude oil assets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. Since 1998, we have completed 12 acquisitions for an aggregate purchase price of $1.1 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, 2002, the amount of costs deferred pending final outcome was not material.

FERC Notice of Proposed Rulemaking. On August 1, 2002, the Federal Energy Regulatory Commission (“FERC”) issued a Notice of Proposed Rulemaking that, if adopted, would amend its Uniform Systems of Accounts for oil pipeline companies with respect to participation of a FERC-Regulated subsidiary in the cash management arrangement of its non-FERC-regulated parent. Although it appears that, if adopted, the rule may affect the way in which we manage cash, we believe that the incremental costs will not be significant.

Sarbanes-Oxley Act and New SEC Rules. Several regulatory and legislative initiatives have been introduced over the past several months in response to recent events regarding accounting issues at large public companies, resulting disruptions in the capital markets and ensuing calls for action to prevent repetition of such events. We support the actions called for under these initiatives and believe these steps will ultimately be successful in accomplishing the stated objectives. However, implementation of reforms in connection with such initiatives will add to the costs of doing business for all publicly-traded entities, including the Partnership. Such costs will have an adverse impact on future income and cash flow, especially in the near term as legal, financial and consultant costs are incurred to analyze the new requirements, formalize current practices and implement required changes to ensure that we maintain compliance with these new rules. We are not able to estimate the magnitude of increase in our costs that will result from such reforms.

Vesting of Unit Grants under LTIP. In connection with our public offering in 1998, our general partner established a long-term incentive plan, which permits the grant of restricted units and unit options covering an aggregate of approximately 1.4 million units. Approximately 1.0 million restricted units (and no unit options) have been granted under the plan. A restricted unit grant entitles the grantee to receive a common unit upon the vesting of the restricted unit. Subject to additional vesting requirements, restricted units may vest in the same proportion as the conversion of our outstanding subordinated units into common units. Certain of the restricted unit grants contain additional vesting requirements tied to the Partnership achieving targeted distribution thresholds, generally $2.10, $2.30 and $2.50 per unit, in equal proportions.

Under generally accepted accounting principles, we are required to recognize an expense when the financial tests for conversion of subordinated units and required distribution levels are met. The test associated with the conversion of subordinated units to common units is set forth in the Partnership Agreement and involves GAAP accounting concepts as well as complex and esoteric cash receipts and disbursement concepts that are indexed to the minimum quarterly distribution rate of $1.80 per limited partner unit.

Because of this complexity, it is difficult to forecast when the vesting of these restricted units will occur. However, at the current distribution level of $2.15 per unit, assuming the subordination conversion test is met, the costs associated with the vesting of up to approximately 820,000 units would be incurred or accrued in the second half of 2003 or the first quarter of 2004. At a distribution level of $2.30 to $2.49, the number of units would be approximately 940,000. At a distribution level at or above $2.50, the number of units would be approximately 1,030,000. We are currently planning to issue units to satisfy the first 975,000 vested, and to purchase units in the open market to satisfy any vesting obligations in excess of that amount. Issuance of units would result in a non-cash compensation expense. Purchase of units would result in a cash charge to compensation expense. The amount of the charge to expense will be determined by the unit price on the date vesting occurs, multiplied by the number of units.

Liquidity and Capital Resources

Liquidity

Cash generated from operations and our credit facilities are our primary sources of liquidity. At September 30, 2002, we had a working capital deficit of approximately $17.8 million, approximately $437.5 million of availability under our revolving credit facility and $53.3 million under the letter of credit and hedged inventory facility. Usage of the credit facilities is subject to compliance with covenants. In the past, we have generally maintained a positive working capital position. During the third quarter of 2002, we reduced our working capital, primarily through the (i) collection of accounts receivable and certain prepayments and the application of those proceeds to reduce its long-term borrowings, and (ii) shifting borrowings to finance certain contango inventory and LPG purchase requirements from its long-term revolving credit facilities to its hedged inventory and letter of credit facility. The hedged inventory and letter of credit facility requires reduction in outstanding amounts at the time proceeds from the sale of the inventory are collected. Accordingly, amounts drawn under this facility are reflected as a current liability for hedged inventory expected to be sold within one year. In addition, approximately $11.3 million of the company’s net liability under SFAS 133 is reflected as current.

We funded the purchase of the Shell acquisition on August 1, 2002, with funds drawn on its revolving credit facilities. Later in August, we completed a public offering of 6,325,000 common units priced at $23.50 per unit. Net proceeds from the offering, including our general partner’s proportionate capital contribution and expenses associated with the offering, were approximately $145.0 million and were used to pay down our revolving credit facilities. During September 2002, we completed the sale of $200 million of 7.75% senior notes due in October 2012, which generated net proceeds of $196.3 million that we used to pay down our revolving credit facilities.

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

Recent Disruptions in Industry Credit Markets. As a result of business failures, revelations of material misrepresentations and related financial restatements by several large, well-known companies in various industries over the last year, 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 troubling disclosures by several large, diversified energy companies, the energy industry has been especially impacted by these developments, with the rating agencies downgrading a number of large energy related companies. Accordingly, in this environment we are exposed to an increased level of direct and indirect counterparty credit and performance risk.

To date, these market disruptions have not had a material adverse impact on our activities or on obtaining open credit for our account with counterparties. We are currently rated BB+ by Standard & Poor’s and on June 27, 2002, we were placed on Credit Watch with positive implications. On September 17, 2002, Moody’s Investor Services upgraded our senior implied credit rating to Ba1, stable outlook. You should note that a rating is not a recommendation to buy, sell, or hold securities, and may be subject to revision or withdrawal at any time.

Cash Flows

	Nine Months Ended September 30,
	2002			2001
	(in millions)
Cash provided by (used in):
Operating activities	$	127.4		$	5.5
Investing activities		(349.8	)		(221.3	)
Financing activities		223.3			216.2

Operating Activities. Net cash provided by operating activities for the nine months ended September 30, 2002 was $127.4 million as compared to $5.5 million in the 2001 period. Approximately $15.5 million of the increase is due to an increase in earnings, adjusted for non-cash items, predominantly related to our acquisitions completed in April and July 2001 and August 2002. The remainder of the increase is due to changes in working capital items related to the following: i) the collection of accounts receivable related to prior period balances as discussed in “Recent Disruptions in Industry Credit Markets” above; ii) the collection of prepayments due to the increase in credit risk associated with certain counter-parties; and iii) the sale of hedged crude oil inventory purchased in 2001 and 2002 and the correlated changes in accounts receivable and accounts payable. In addition to the hedged inventory transactions having a positive effect on cash provided by operating activities for the nine months ended September 30, 2002, similar transactions had a negative effect on the nine months ended September 30, 2001 as the inventory was being purchased and stored; thus, resulting in an even larger variance when comparing the two periods.

Investing Activities. Net cash used in investing activities in 2002 includes the payment of $310.1 million related to the purchase of certain assets from Shell Pipeline Company as well as related transaction costs, $7.7 million for the Butte acquisition and $5.1 million for the Coast/Lantern acquisition. Investing activities also

includes $27.4 million of capital expenditures related to the Cushing expansion, the construction of the Marshall terminal in Canada and other capital projects.

Financing Activities. Cash provided by financing activities in 2002 consisted of approximately $351.3 million of proceeds from the issuance of common units and senior unsecured notes used primarily to fund capital projects and acquisitions and pay down outstanding balances on the revolving credit facility. In addition, $71.6 million of distributions were paid to unitholders and the general partner during the nine months ended September 30, 2002.

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, 2002, we have approximately $421 million remaining under this registration statement.

Credit Facilities and Long-term Debt

The facilities have final maturities as follows:

•

as to the $350.0 million senior secured letter of credit and hedged inventory facility and the aggregate $450.0 million domestic and Canadian revolver portions, in April 2005;

•

as to the $99.0 million term loan, in May 2006; and

•

as to the $198.0 million term B loan, in September 2007.

The financial covenants of these credit facilities require us to maintain:

•

a current ratio (as defined) of at least 1.0 to 1.0;

•

a debt coverage ratio which will not be greater than 5.25 to 1.0 on unsecured debt and 4.0 to 1.0 on secured debt;

•

an interest coverage ratio that is not less than 2.75 to 1.0; and

•

a debt to capital ratio of not greater than 0.7 to 1.0 through March 30, 2003, and 0.65 to 1.0 at any time thereafter.

The amended facility permits us to issue up to an aggregate $400 million of senior unsecured debt having a maturity beyond the final maturity of the existing credit facility and provides a mechanism to reduce the amount of the domestic revolving credit facility. The foregoing description of the credit facility incorporates the reduction associated with the $200 million senior note offering completed in September 2002. Depending on the amount of additional senior indebtedness incurred, the domestic revolving credit facility will be reduced by an amount equating to 40% to 63% of any incremental indebtedness, up to the aggregate $400 million limitation.

The average life of our debt capitalization at September 30, was approximately 6.5 years. At the end of the third quarter we had approximately $12 million outstanding under our $450 million of revolving credit facilities that mature in 2005, approximately $297 million of senior secured term loans with final maturity dates in 2006 and 2007 and $200 million of senior notes which mature in 2012. We have classified the $9 million of term loan payments due in 2003 as long term due to our intent and ability to refinance those maturities using the revolving facility.

Term loan payments are as follows (in millions):

Calendar Year	Payment
2003	$	9.0
2004		10.0
2005		10.0
2006		78.0
2007		190.0

Total	$	297.0

We manage our exposure to increasing interest rates. Based on September 30, 2002, debt balances, floating rate indexes at the end of October 2002, our credit spread under our credit facilities and the combination of our fixed rate debt and current interest rate hedges, the average interest rate was approximately 6.2%, excluding non-use and facilities fees, which will vary based on usage and outstanding balance. Based on current amounts outstanding, we estimate these fees will average approximately $2.2 million per year. We have locked-in interest rates (excluding the credit spread under the credit facilities) for approximately 60% of our total debt for the next year, 50% for the next four years and 40% for the next ten years.

Contingencies

Pipeline and Storage Regulation. We are subject to the U.S. Department of Transportation’s (the “DOT’s”) pipeline integrity rules, which require continual assessment of pipeline segments that could affect “high consequence areas.” Our compliance costs will vary from year to year based on the assessment priority placed on particular line segments. Based on currently available information, we estimate that such costs will average approximately $2.5 million per year in 2003 and 2004. Such amounts incorporate approximately $1 million per year associated with assets acquired in the Shell acquisition. We will continue to refine our estimates as data from initial assessments is collected.

The DOT has adopted API 653 as the standard for the inspection, repair, alteration and reconstruction of existing crude oil storage tanks subject to DOT jurisdiction (approximately 72% of our 21.3 million barrels). API 653 requires regularly scheduled inspection and repair of tanks remaining in service. Full compliance is required by 2009. We have commenced our compliance activities under the standard and, based on currently available information, we estimate that we will spend approximately $3 million per year in 2003 and 2004 in connection with these activities. Such amounts incorporate costs associated with assets acquired in the Shell acquisition. We will continue to refine our estimates as data from initial assessments is collected.

Other. A pipeline, terminal 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. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers all of our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The events of September 11, 2001, and their overall effect on the insurance industry has had adverse impact on availability and cost of coverage. Due to these events, insurers have excluded acts of terrorism and sabotage from our insurance policies. On certain of our key assets, we purchased a separate insurance policy for acts of terrorism and sabotage.

Recent Accounting Pronouncements

In October 2002, the Emerging Issues Task Force (“EITF”) reached consensus on certain issues in EITF Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under Issues No. 98-10 and 00-17.” The consensus reached included i) rescinding EITF 98-10 and ii) the requirement that mark-to-market gains and losses on trading contracts (whether realized or unrealized and whether financially or physically settled) be shown net in the income statement. The EITF provided guidance that, beginning on October 25, 2002, all new contracts that would have been accounted for under EITF 98-10 should no longer be marked-to-market through earnings unless such contracts fall within the scope of SFAS 133. All of the contracts that we have accounted for under EITF 98-10 fall within the scope of SFAS 133 and therefore will continue to be marked-to-market through earnings under the provisions of that rule. Therefore, we do not believe that the adoption of this rule will have a material effect on either our financial position, results of operations or cash flows.

In June 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS 146 “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the obligation is incurred rather than at the date of the exit plan. This Statement is effective for exit or disposal activities that are initiated after December 31, 2002. We do not believe that the adoption of SFAS 146 will have a material effect on either our financial position, results of operations or cash flows.

In April 2002, the FASB issued SFAS 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS No. 145 rescinds, updates, clarifies and simplifies existing accounting pronouncements. Among other things, SFAS No. 145 rescinds SFAS No. 4, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. Under SFAS No. 145, the criteria in Accounting Principles Board No. 30 will now be used to classify those gains and losses. The adoption of this and the remaining provisions of SFAS 145 did not have a material effect on our financial position or results of operations. However, any future extinguishments of debt may impact income from continuing operations.

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, counterparties;

•

successful third party drilling efforts and completion of announced oil-sands projects;

•

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

•

shortages or cost increases of power supplies, materials or labor;

•

weather interference with business operations or project construction;

•

the impact of current and future laws and governmental regulations;

•

the currency exchange rate of the Canadian dollar;

•

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

•

fluctuations in the debt and equity markets; and

•

general economic, market or business conditions.

Other factors described herein, such as the recent disruption in industry credit markets discussed in Liquidity and Capital Resources and in Note 6 to the financial statements 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 information required herein is included in Note 2 of the Notes to the Consolidated Financial Statements.

Item 4. CONTROLS AND PROCEDURES

Under Exchange Act Rule 13a-15, which became effective August 29, 2002, we are required to maintain “disclosure controls and procedures,” as defined in Exchange Act Rule 13a-14(c). As a result of the rule, we have formalized our disclosure practices into a written “disclosure controls and procedures,” which we refer to as our “DCP.” The purpose of our DCP is to ensure that (i) information is recorded, processed, summarized and reported in time to allow for 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.

Exchange Act Rule 13a-15 also requires an evaluation of the effectiveness of the design and operation of our DCP, within the 90-day period prior to filing any 10-Q or 10-K, under the supervision and with the participation of our management, including our Chief Executive Office and Chief Financial Officer. Management (including our Chief Executive Officer and Chief Financial Officer) has evaluated the effectiveness of the design and operation of our DCP within the last 90 days, and have found our DCP to be effective in producing the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.

In addition to the information concerning our DCP, we are required to discuss significant changes in our internal controls. There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the last date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

We have recently commenced an effort to consolidate our internal auditing activities into a centralized function, and have hired a director of internal auditing to oversee that function. As we complete the consolidation of these activities over the next several months, we will make any additional enhancements to our controls and procedures that are deemed appropriate.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Other. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. We do not believe that the outcome of these other legal proceedings, individually and 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

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

A. Exhibits


4.1		Indenture dated as of September 25, 2002.

4.2		First Supplemental Indenture dated as of September 25, 2002.

4.3		Registration Rights Agreement dated September 25, 2002.

99.1		Certification of Chief Executive Officer of Plains All American Pipeline, L.P. pursuant to 18 U.S.C. Section 1350.

99.2		Certification of Chief Financial Officer of Plains All American Pipeline, L.P. pursuant to 18 U.S.C. Section 1350.

B. Reports on Form 8-K.

A current report on Form 8-K was filed on November 8, 2002, including as an exhibit the balance sheet of Plains AAP, L.P. as of June 30, 2002.

A current report on Form 8-KA was furnished on November 5, 2002, to correct certain information in the October 29, 2002, 8-K.

A current report on Form 8-K was furnished on October 29, 2002, in connection with disclosure of fourth quarter estimates and earnings guidance.

A current report on Form 8-K was filed on August 21, 2002, including as an exhibit an underwriting agreement with Goldman, Sachs & Co., Lehman Brothers Inc., Salomon Smith Barney Inc., UBS Warburg LLC, A.G. Edwards & Sons, Inc. and Wachovia Securities, Inc. in connection with the sale by the Partnership of 5,500,000 common units of the Partnership.

A current report on Form 8-K was filed on August 15, 2002, including as exhibits consents of PricewaterhouseCoopers LLP.

A current report on Form 8-K was filed on August 9, 2002, in connection with the certification by the Chief Executive Officer and the Chief Financial Officer pursuant to SEC Order 4-460.

A current report on Form 8-K was filed on August 9, 2002, in connection with the acquisition of assets from Shell Pipeline Company LP and Equilon Enterprises LLC.

A current report on Form 8-K was furnished on July 24, 2002, in connection with disclosure of third quarter estimates and earnings guidance.

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 11, 2002

By: /s/ PHILLIP D. KRAMER

Phillip D. Kramer, Executive Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

Date: November 11, 2002

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)

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PLAINS ALL AMERICAN PIPELINE, L.P.

I, Greg L. Armstrong, certify that:

I have reviewed this quarterly report on Form 10-Q of Plains All American Pipeline, L.P.;

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

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

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

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 11, 2002

/s/ GREG L. ARMSTRONG

Greg L. Armstrong

Chief Executive Officer

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PLAINS ALL AMERICAN PIPELINE, L.P.

I, Phillip D. Kramer, certify that:

I have reviewed this quarterly report on Form 10-Q of Plains All American Pipeline, L.P.;

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

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 11, 2002

/s/ PHILLIP D. KRAMER

Phillip D. Kramer

Chief Financial Officer

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