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TABLE OF CONTENTS

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

Commission file number: 1-14569

PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)

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

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

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

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

TABLE OF CONTENTS

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

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

Note 2—Acquisitions and Dispositions

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

ArkLaTex Pipeline System

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

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

Other Acquisitions

        During the first half of 2003, we made six acquisitions from various entities for an aggregate purchase price of $85.7 million. These acquisitions included mainline crude oil pipelines, crude oil gathering lines, terminal and storage facilities, and an underground LPG storage facility. With the exception of $3.0 million that was allocated to investment in affiliates and $0.5 million that was allocated to goodwill and other intangible assets, the remaining aggregate purchase price was allocated to property and equipment.

Shutdown of Rancho Pipeline System

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

Note 3—Trade Accounts Receivable

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

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

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

Note 4—Debt

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

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

(1)

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

Note 5—Earnings Per Common Unit

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

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

Note 6—Partners' Capital and Distributions

Distributions

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

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

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

Equity Offerings

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

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

Subordinated Unit Conversion

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

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

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

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

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Probable Vesting

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

Potential Vesting

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

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

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Note 8—Derivative Instruments and Hedging Activities

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

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

Summary of Financial Impact

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

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

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

Commodity Price Risk Hedging

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

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

Controlled Trading Program

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

Interest Rate Risk Hedging

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

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

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

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

Currency Exchange Rate Risk Hedging

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

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

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

Note 9—Commitments and Contingencies

Litigation

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

Indemnities

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

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

Environmental

        We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. We believe that our reserve for environmental liabilities is adequate. However, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.

Contingent Equity Issuance

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

Asset Retirement Obligation

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

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

Other

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

        The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe we are adequately insured for public liability and property damage to others with respect to our operations. We believe that our levels of coverage and retention are generally consistent with those of similarly situated companies in our industry. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable, or that we have established adequate reserves to the extent that such risks are not insured.

Note 10—Operating Segments

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

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

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(1)

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

(2)

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

(3)

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

(4)

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

Note 11—Recent Accounting Pronouncements

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

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

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

Overview

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

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

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

Acquisitions

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

ArkLaTex Pipeline System

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

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

Other Acquisitions

        During the first half of 2003, we made six acquisitions from various entities for an aggregate purchase price of $85.7 million. These acquisitions included mainline crude oil pipelines, crude oil gathering lines, terminal and storage facilities, and an underground LPG storage facility. With the exception of $3.0 million that was allocated to investment in affiliates and $0.5 million that was allocated to goodwill and other intangible assets, the aggregate purchase price was allocated to property and equipment.

2002 Acquisitions

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

Results of Operations

        Our operations consist of two operating segments: (1) our Pipeline Operations, through which we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities; and (2) our Gathering, Marketing, Terminalling and Storage Operations, through which we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. We evaluate segment performance based on (i) gross margin (excluding depreciation), (ii) gross profit (excluding depreciation), which is gross margin (excluding depreciation) less general and administrative expenses and (iii) on an annual basis, maintenance capital. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred. Our current estimate of maintenance capital expenditures for 2003 is approximately $6.9 million. We monitor maintenance capital expenditures on an annual basis, since these capital projects can overlap quarters and may be impacted by weather, permitting and other uncontrollable delays. Accordingly, no period-by-period analysis is provided, except on an annual basis.

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Three Months Ended September 30, 2003 and 2002

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

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

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

(1)

Revenues and costs of sales and operations include intersegment amounts.

(2)

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

(3)

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

Pipeline Operations

        As of September 30, 2003, we owned and operated over 6,200 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting volumes of crude oil for a fee and third-party leases of pipeline capacity (tariff activities), as well as barrel exchanges and buy/sell arrangements (margin activities). In connection with certain of our merchant activities conducted under our gathering and marketing business, we are also shippers on certain of our own pipelines. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The gross margin (excluding depreciation) generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable costs of operating the pipeline. Gross margin (excluding depreciation) from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

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