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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2003

OR

Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.

(Exact name of registrant as specified in its charter)

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 ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).    Yes þ No ¨

At April 30, 2003, there were outstanding 40,885,939 Common Units, 1,307,190 Class B Common Units and 10,029,619 Subordinated Units.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

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PART I. FINANCIAL INFORMATION

Item 1.    CONSOLIDATED FINANCIAL STATEMENTS

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(in thousands)

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(in thousands)

Statements of Comprehensive Income

Statement of Changes in Accumulated Other Comprehensive Income

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

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

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

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

Note 2—Acquisitions and Dispositions

Red River Pipeline System

In February 2003, we completed the acquisition of a 347-mile crude oil pipeline from BP Pipelines (North America) Inc. for approximately $19.3 million, including transaction costs. The system originates at Sabine in East Texas and terminates near Cushing, Oklahoma. The system also includes approximately 695,000 barrels of crude oil storage capacity. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since February 1, 2003. The entire purchase price was allocated to property and equipment. This pipeline complements our existing assets in East Texas and, upon completion of a planned interconnect, will provide another direct mainline connection to our Cushing Terminal. This acquisition did not have a material effect on either our financial position, results of operations or cash flows.

Iatan Gathering System

In March 2003, we completed the acquisition of a West Texas crude oil gathering system from Navajo Refining Company, L.P. for approximately $24.3 million, including transaction costs. The assets are located in the Permian Basin in West Texas and consist of approximately 315 miles of active crude oil gathering lines. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2003. The entire purchase price was allocated to property and equipment. This acquisition did not have a material effect on either our financial position, results of operations or cash flows.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Shutdown of Rancho Pipeline System

The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, terminated in March 2003. Upon termination, the agreement requires the owners to take the pipeline system, in which we own an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not accept nominations for movements after February 28, 2003. The shutdown of the Rancho Pipeline System was contemplated by us at the time we made our acquisition proposal. The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. The ultimate use of the Rancho pipeline is still being evaluated by the owners, however any value realized is expected to be minimal and relatively close to the purchase price allocated to this asset. In conjunction with the Shell acquisition in 2002 the shutdown of the Rancho pipeline was accounted for under purchase accounting in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 141 “Business Combinations.”

Note 3 – Industry Credit Markets and Accounts Receivable

Throughout the latter part of 2001 and all of 2002, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and extreme financial distress at several large, diversified energy companies, the energy industry has been especially impacted by these developments. Accordingly, we are exposed to an increased level of direct and indirect counterparty credit and performance risk.

Our accounts receivable are primarily from purchasers and shippers of crude oil. The majority of our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. We make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided in the form of standby letters of credit.

Accounts receivable included in the consolidated balance sheets are reflected net of our allowance for doubtful accounts. We routinely review our receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such delays involve billing delays and discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. At December 31, 2002 approximately 99% of net accounts receivable classified as current were less than 60 days past scheduled invoice date and our allowance for doubtful accounts receivable classified as current totaled $3.1 million, representing 31% of all receivable balances greater than 60 days past the scheduled invoice date. At December 31, 2002 approximately $6.5 million of net accounts receivable were classified as long-term and our allowance for doubtful accounts receivable classified as long-term totaled $5.0 million representing 43% of all long-term receivable balances.

During the first quarter of 2003 we continued our concerted effort to reconcile any remaining discrepancies with third parties and bring substantially all receivable balances to within sixty days of scheduled invoice date. During this period we resolved several issues and discrepancies, realized collections from various third parties and made corresponding adjustments to related receivable and payable balances. As a result, the aggregate balance of net accounts receivable balances classified as long-term was reduced by 54% to a remaining balance of $3.0 million at March 31, 2003. The net balance of receivables classified as current that were greater than 60 days past the scheduled invoice date were reduced by 13% and constituted approximately 1% of the total net accounts receivable balance classified as current. Our allowance for doubtful accounts receivable classified as

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

current and long-term at March 31, 2003 totaled $3.1 million and $5.0 million, respectively, representing 34% and 63% of such respective gross balances. We believe the remaining net receivable balances greater than sixty days past scheduled invoice date are collectible or subject to offsets and consider our reserves adequate. However, since these obligations are not currently secured by letters of credit, in the event our counterparties experience an unanticipated deterioration in their credit-worthiness, any addition to existing reserves or write-offs in excess of such reserves would result in a charge to earnings. We do not believe any such charge would have a material effect on our cash flow or liquidity.

Note 4—Partners’ Capital and Distributions

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

On April 24, 2003, we declared a cash distribution of $0.55 per unit on our outstanding common units, Class B common units and subordinated units. The distribution is payable on May 15, 2003, to unitholders of record on May 5, 2003, for the period January 1, 2003, through March 31, 2003. The total distribution to be paid is approximately $30.6 million, with approximately $23.2 million to be paid to our common unitholders, $5.5 million to be paid to our subordinated unitholders and $0.6 million and $1.3 million to be paid to our general partner for its general partner and incentive distribution interests, respectively. The distribution is in excess of the minimum quarterly distribution specified in the partnership agreement.

On January 24, 2003, we declared a cash distribution of $0.5375 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid on February 14, 2003, to unitholders of record on February 4, 2003, for the period October 1, 2002, through December 31, 2002. The total distribution paid was approximately $28.2 million, with approximately $21.2 million paid to our common unitholders, $5.4 million paid to our subordinated unitholders and $0.6 million and $1.0 million paid to our general partner for its general partner and incentive distribution interests, respectively. The distribution was in excess of the minimum quarterly distribution specified in the partnership agreement.

Note 5—Derivative Instruments and Hedging Activities

We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk.

Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX and over-the-counter positions, and physical volumes, grades, locations and delivery schedules to ensure that our hedging activities address our market risks. We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Summary of Financial Impact

The following is a summary of the financial impact of the derivative instruments and hedging activities discussed below. The March 31, 2003, balance sheet includes assets of $25.9 million ($24.4 million current), liabilities of $27.8 million ($14.9 million current) and related unrealized net losses deferred to Other Comprehensive Income (“OCI”) of $3.9 million. In addition, revenues for the three months ended March 31, 2003, included a noncash gain of $0.9 million ($1.9 million noncash gain before the reversal of the prior period fair value adjustment related to contracts that settled during the current period). Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet.

As of March 31, 2003, the total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. During the three months ended March 31, 2003 and 2002, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Of the $3.9 million net loss deferred to OCI at March 31, 2003, a gain of $6.6 million will be reclassified to earnings in the next twelve months and the remainder by December 2005. Since these amounts are based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

Commodity Price Risk Hedging

We hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments utilized consist primarily of futures and option contracts traded on the New York Mercantile Exchange and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies. In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” these derivative instruments are recognized in the balance sheet or earnings at their fair values. The majority of our commodity price risk derivative instruments qualify for hedge accounting as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into OCI and recognized in revenues or cost of sales and operations in the periods during which the underlying physical transactions occur. We have determined that our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133. At March 31, 2003 and 2002, there was a gain of $7.0 million and a loss of $5.3 million, respectively, deferred in OCI related to our commodity price risk activities. The amount included in earnings due to changes in the fair value of derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective for the three months ended March 31, 2003 and 2002, was a gain of $1.0 million and a loss of $2.9 million, respectively.

Controlled Trading Program

From time to time, we experience net unbalanced positions as a result of production and delivery variances associated with our lease purchase activities. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to 500,000 barrels. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

in fair value recorded net in revenues. Although there were no open positions under this program at March 31, 2003 and 2002, the realized earnings impact related to these derivatives for the three months ended March 31, 2003 and 2002 was a loss of $0.1 million and $0.2 million, respectively.

Interest Rate Risk Hedging

We utilize various products, such as interest rate swaps, collars and treasury locks to hedge interest obligations on specific debt issuances, including anticipated debt issuances. During the first quarter of 2003, we converted a $50 million treasury lock into a 10-year LIBOR-based swap that becomes effective in March 2004, as discussed below, contemporaneously with the expiration of an existing $50 million LIBOR-based swap. The instruments outstanding at March 31, 2003, consist of three separate interest rate swaps with an aggregate notional principal amount of $100.0 million outstanding at any one time. The interest rate swaps are based on LIBOR rates and provide for a LIBOR rate of 5.1% for a $50.0 million notional principal amount expiring October 2006, a LIBOR rate of 4.3% for a $50.0 million notional principal amount expiring March 2004 and a LIBOR rate of 5.8% for a $50 million notional principal amount that commences in March 2004 and expires in March 2014. We believe all of these instruments are placed with large creditworthy financial institutions. Interest on the underlying debt is based on LIBOR plus a margin.

These instruments qualify for hedge accounting as cash flow hedges in accordance with SFAS 133. The effective portion of changes in fair values of these hedges is recorded in OCI until the related hedged item impacts earnings. At March 31, 2003 and 2002, there were losses of $10.8 million and $2.7 million, respectively, deferred in OCI related to our interest rate risk activities. For the three months ended March 31, 2003 and 2002, there were no amounts recognized into earnings related to hedge ineffectiveness.

At March 31, 2003, our average interest rate, excluding non-use and facilities fees, was approximately 6.2%. This rate is based on our March 31, 2003 debt balances and floating rate indices, our credit spread under our credit facilities and the combination of our fixed rate debt and current interest rate hedges. We have locked-in interest rates (excluding the credit spread under the credit facilities) for approximately 57% of our total long-term debt through October 2006, and 48% for the period from October 2006 through September 2012.

Currency Exchange Rate Risk Hedging

Since a significant portion of our Canadian business is conducted in Canadian dollars (CAD), we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include forward exchange contracts, forward extra option contracts and cross currency swaps. Additionally, at March 31, 2003, $1.4 million of our long-term debt was denominated in Canadian dollars ($2.1 million CAD based on a Canadian-U.S. dollar exchange rate of 1.47).

At March 31, 2003, we had forward exchange contracts and forward extra option contracts that allow us to exchange $3.0 million Canadian for at least $1.9 million U.S. quarterly during 2003 (based on a Canadian-U.S. dollar exchange rate of 1.54). At March 31, 2003, we also had cross currency swap contracts for an aggregate notional principal amount of $24.8 million, effectively converting this amount of our senior secured term loan to $38.3 million of Canadian dollar debt (based on a Canadian-U.S. dollar exchange rate of 1.55). The terms of this contract mirror the term loan, matching the amortization schedule and final maturity in May 2006. We believe all of these financial instruments are placed with large creditworthy financial institutions.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

The forward exchange contracts and forward extra option contracts qualify for hedge accounting as cash flow hedges, in accordance with SFAS 133. Such derivative activity resulted in a loss of $0.1 million and a gain of $0.3 million deferred in OCI at March 31, 2003 and 2002, respectively. The cross currency swaps qualify for hedge accounting as fair value hedges, also in accordance with SFAS 133. The earnings impact related to our cross currency swaps was a loss of $0.1 million for the three months ended March 31, 2003 and a nominal amount for the three months ended March 31, 2002.

Note 6—Commitments and Contingencies

Export License Matter.    In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the short supply controls of the Export Administration Regulations (the “EAR”) and must be licensed by the Bureau of Industry and Security (the “BIS”) of the U.S. Department of Commerce. We have determined that we have exceeded the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of these potential violations.

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

Other.    Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets (including our nation’s pipeline infrastructure) may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. The Department of Transportation (“DOT”) has developed a security guidance document and has issued a security circular that defines critical pipeline facilities and appropriate countermeasures for protecting them, and explains how the DOT plans to verify that operators have taken appropriate action to implement satisfactory security procedures and plans. Using the guidelines provided by the DOT, we have specifically identified certain of our facilities as DOT “critical facilities” and therefore potential terrorist targets. In compliance with DOT guidance, we performed vulnerability analyses on our critical facilities and have instituted, or will institute as appropriate, any indicated security measures or procedures that are not already in place. The Transportation Safety Administration (an agency of the Department of Homeland Security, which is in the transitional phase of assuming responsibility from the DOT) may issue additional guidelines. We cannot assure you that these or any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not.

We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business.

The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

We believe that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

We are party to various contracts entered into in the ordinary course of business that contain indemnity provisions pursuant to which we indemnify the counterparties against various expenses. Our indemnity obligations are contingent upon the occurrence of events or circumstances specified in the contracts. No such events or circumstances have occurred at this time, and we do not consider our liability under such indemnity provisions, individually or in the aggregate, to be material to our financial position or results of operations.

Note 7—Operating Segments

Our operations consist of two operating segments: (1) our Pipeline Operations through which we engage in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; and (2) our Gathering, Marketing, Terminalling and Storage Operations through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on (i) gross margin (excluding depreciation), (ii) gross profit (excluding depreciation), which is gross margin (excluding depreciation) less general and administrative expenses and (iii) on an annual basis, maintenance capital. Maintenance capital consists of expenditures required to maintain the existing operating capacity of partially or fully depreciated assets or extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred.

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Note 8—Recent Accounting Pronouncements

In December 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 148 “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 in both annual and interim financial statements. SFAS 148 is effective for financial statements for fiscal years ending after December 15, 2002, and financial reports containing condensed financial statements for interim periods beginning after December 15, 2002. Our general partner has equity-based employee compensation plans. These plans are accounted for under the fair value based method as described in SFAS 123. Therefore, the adoption of this statement did not have a material effect on either our financial position, results of operations, cash flows or disclosure requirements.

In June 2002, the FASB issued SFAS No. 146 “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the obligation is incurred rather than at the date of the exit plan. This Statement is effective for exit or disposal activities that are initiated after December 31, 2002. We have not initiated any material exit or disposal activities that are subject to this statement and do not believe that the adoption of SFAS 146 will have a material effect on either our financial position, results of operations or cash flows.

In June 2001, the FASB issued SFAS No. 143 “Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the time of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to

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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Effective January 1, 2003, we adopted SFAS 143, as required. Determination of the amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. The majority of our assets, primarily related to our pipeline operations segment, have obligations to perform remediation and, in some instances, removal activities when the asset is retired. However, the fair value of the asset retirement obligations cannot be reasonably estimated, as the settlement dates are indeterminate. We will record such asset retirement obligations in the period in which we determine the settlement dates. The adoption of this statement did not have a material impact on our financial position, results of operations or cash flows. See Note 2 for the accounting treatment of the shutdown of the Rancho Pipeline System.

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

Overview

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

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

Internally, we also exclude from our operating results the impact of other items we consider to impact comparability between periods. To comply with the new regulations effective in March 2003, we have omitted certain adjustments and reconciliations related to these items that have been presented in the past. We have also changed the format of certain tables presented in the discussion of our results of operations. In addition, certain reclassifications have been made to prior period amounts to conform to current period presentation. Where appropriate, we have noted that reported results include the effects of items we consider to impact comparability between periods. Overall, we believe the discussion and presentation provides an accurate and thorough analysis of our results of operations and financial condition. Additionally, we will maintain on our website (www.paalp.com) a reconciliation of all non-GAAP financial information that we disclose to the most comparable GAAP measures. To access the information, investors should click on the “Non-GAAP Reconciliations” link on our home page.

Acquisitions

We completed several acquisitions during 2002 and 2003 that have impacted the results of operations and liquidity discussed herein. These acquisitions are discussed below and our ongoing acquisition activity is discussed further in “Liquidity and Capital Resources.”

Red River Pipeline System

In February 2003, we completed the acquisition of a 347-mile crude oil pipeline from BP Pipelines (North America) Inc. for approximately $19.3 million in cash, including transaction costs. The system originates at Sabine in East Texas and terminates near Cushing, Oklahoma. The system also includes approximately 695,000 barrels of crude oil storage capacity. We plan to replace approximately 32 miles of existing pipe on this pipeline and to build a twelve-mile extension of the system to connect to our terminal in Cushing. We estimate the total cost of the projects to be approximately $14.0 million, of which approximately $6.0 million will be spent in

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2003 and approximately $8.0 million will be spent in 2004. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since February 1, 2003. The entire purchase price was allocated to property and equipment. This pipeline complements our existing assets in East Texas and, upon completion of the planned interconnect, will provide another direct mainline connection to our Cushing Terminal.

Iatan Gathering System

In March 2003, we completed the acquisition of a West Texas crude oil gathering system from Navajo Refining Company, L.P for approximately $24.3 million, including transaction costs. The assets are located in the Permian Basin in West Texas and consist of approximately 315 miles of active crude oil gathering lines. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2003. The entire purchase price was allocated to property and equipment.

2002 Acquisitions

In August 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 8.9 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the “Shell acquisition”) for approximately $324 million. In March 2002, we acquired substantially all of the domestic crude oil pipeline, gathering and marketing assets of Coast Energy Group and Lantern Petroleum, divisions of Cornerstone Propane Partners, L.P., for approximately $8.3 million. In February 2002, we acquired an approximate 22% equity interest in Butte Pipeline Company (the “Butte acquisition”) for approximately $7.6 million.

Results of Operations

For the three months ended March 31, 2003, we reported net income of $24.4 million on total revenues of $3.3 billion compared to net income for the same period in 2002 of $14.3 million on total revenues of $1.5 billion. Our net income includes a $0.9 million gain and a $2.9 million loss related to SFAS 133 for the quarters ended March 31, 2003 and 2002, respectively.

Our operations consist of two operating segments: (1) our Pipeline Operations, through which we engage in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; and (2) our Gathering, Marketing, Terminalling and Storage Operations, through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on (i) gross margin (excluding depreciation), (ii) gross profit (excluding depreciation), which is gross margin (excluding depreciation) less general and administrative expenses and (iii) on an annual basis, maintenance capital. Maintenance capital consists of expenditures required to maintain the existing operating capacity of partially or fully depreciated assets or extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. For 2003, we have budgeted annual maintenance capital expenditures of $8.5 million. We monitor maintenance capital expenditures on an annual basis, since these capital projects can overlap quarters and may be impacted by weather, permitting and other non-controllable delays. Accordingly, no quarter by quarter analysis is provided. The following table reflects our results of operations for each segment:

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Pipeline Operations

As adjusted for acquisitions completed in the first quarter of 2003 and the shut down of the Rancho Pipeline System which commenced in March 2003, we own and operate over 5,800 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting volumes of crude oil for a fee, third-party leases of pipeline capacity, barrel exchanges and buy/sell arrangements. We also use our pipelines in our merchant activities conducted under our gathering and marketing business. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The gross margin (excluding depreciation) generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable costs of operating the pipeline. Gross margin (excluding depreciation) from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

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

Total average daily volumes transported were approximately 818,000 barrels per day and 464,000 barrels per day for the three months ended March 31, 2003 and 2002, respectively. As discussed above, we have completed a number of acquisitions during 2003 and 2002 that have impacted the results of operations herein. The following table reflects our total average daily volumes from our tariff activities by year of acquisition for comparison purposes:

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Average daily volumes from our tariff activities were approximately 732,000 barrels per day compared to approximately 393,000 barrels per day for the prior year quarter. Approximately 336,000 barrels per day of the increase in the current year quarter is due to volumes transported on the pipelines acquired in 2003 and 2002, including approximately 316,000 on the assets acquired in the Shell acquisition. In addition, we transported approximately 20,000 barrels per day more on our Canadian pipelines in the current year quarter than in the prior year quarter. This increase in the first quarter of 2003 over the prior year quarter is due to the completion of capital expansion projects during 2002 that allowed for additional volumes on certain of our Canadian pipelines. The increase in volumes from our Canadian pipelines were substantially offset by decreases on various domestic pipeline systems including an approximate 8,000 barrel per day decrease in our All American tariff volumes attributable to California outer continental shelf (“OCS”) production.

Total revenues from our pipeline operations were approximately $169.0 million and $88.5 million for the three months ended March 31, 2003 and 2002, respectively. The increase in revenues was primarily related to our merchant margin activities, which increased by approximately $67.4 million in the first quarter of 2003. This increase was primarily related to higher average prices on our merchant activity on our San Joaquin Valley gathering system in the 2003 period as compared to the 2002 period, but was also positively impacted by higher volumes on our buy/sell arrangements in the current period. However, this business is a margin business and although revenues and cost of sales are impacted by the absolute level of crude oil prices, there is a limited impact on gross margin.

Revenues from our tariff activities increased approximately $13.1 million. The following table reflects our revenues from our tariff activities by year of acquisition for comparison purposes: