PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

        Plains All American Pipeline, L.P. is a publicly traded Delaware limited partnership (the "Partnership") engaged in interstate and intrastate crude oil transportation, and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other petroleum products. We refer to liquefied petroleum gas and other petroleum products collectively as "LPG." Our operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P., Plains Pipeline, L.P. (formerly known as All American Pipeline, L.P.) and Plains Marketing Canada, L.P., and are concentrated in Texas, Oklahoma, California, Louisiana and the Canadian provinces of Alberta and Saskatchewan.

        The accompanying consolidated financial statements and related notes present (i) our consolidated financial position as of March 31, 2004, and December 31, 2003, (ii) the results of our consolidated operations for the three months ended March 31, 2004 and 2003, (iii) our consolidated cash flows for the three months ended March 31, 2004 and 2003, (iv) our consolidated changes in partners' capital for the three months ended March 31, 2004, (v) our consolidated comprehensive income for the three months ended March 31, 2004 and 2003, and (vi) our changes in consolidated accumulated other comprehensive income for the three months ended March 31, 2004. The financial statements have been prepared in accordance with the instructions for interim reporting as prescribed by the Securities and Exchange Commission. All adjustments (consisting only of normal recurring adjustments) that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. Certain reclassifications are made to prior period amounts to conform to current period presentation. The results of operations for the three months ended March 31, 2004 should not be taken as indicative of the results to be expected for the full year. The consolidated interim financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our 2003 Annual Report on Form 10-K.

Note 2—Acquisitions

Capline and Capwood Pipeline Systems

        In March 2004, we completed the acquisition of all of Shell Pipeline Company LP's interests in two entities for approximately $158.0 million in cash (including a $15.8 million deposit paid in December 2003) and approximately $0.5 million of transaction and other costs. The acquisition was accounted for under Statement of Financial Accounting Standards ("SFAS") No. 141 "Business Combinations." In December 2003, subsequent to the announcement of the acquisition and in anticipation of closing, we issued approximately 2.8 million common units for net proceeds of approximately $88.4 million. The proceeds from this issuance were used to pay down our revolving credit facility. At closing, the cash portion of this acquisition was funded from cash on hand and borrowings under our revolving credit facility.

        The principal assets of these entities are: (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 667-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The results of operations and assets from this acquisition (the "Capline acquisition") have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2004. These pipelines provide one of the primary transportation routes for crude oil shipped into the Midwestern U.S., and delivered to several refineries and other pipelines.

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        The purchase price was allocated as follows (in millions):

        The following unaudited pro forma data is presented to show pro forma revenues, net income and basic and diluted net income per limited partner unit for the Partnership as if the Capline acquisition had occurred as of the beginning of the periods reported (in millions, except per unit amounts):

Note 3—Trade Accounts Receivable

        The majority of our trade accounts receivable relate to our gathering and marketing activities and can generally be described as high volume and low margin activities. We routinely review our trade accounts receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such uncollected amounts involve billing delays and discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered, received or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable. At March 31, 2004, approximately 99% of our net trade accounts receivable were less than 60 days past the scheduled invoice date. Our allowance for doubtful accounts receivable totaled $0.2 million. We consider this reserve adequate; however, there is no assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.

Note 4—Earnings Per Common Unit

        The following table sets forth the computation of basic and diluted earnings per limited partner unit. The net income available to limited partners and the weighted average limited partner units outstanding

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have been adjusted for the dilutive effect of the contingent equity issuance related to the CANPET acquisition (see Note 5).

(1)

For purposes of calculating diluted earnings per limited partner unit we have assumed that the April 2004 contingent equity issuance related to the CANPET acquisition would be settled entirely in units, in accordance with SFAS No. 128 "Earnings Per Share." See Note 5 for the actual number of units issued to settle the obligation.

Note 5—Partners' Capital and Distributions

Subordinated Unit Conversion

        Pursuant to the terms of our Partnership Agreement, in November 2003, 25% of the Subordinated Units converted to Common Units on a one-for-one basis. In February 2004, all of the remaining Subordinated Units converted to Common Units on a one-for-one basis.

        As of December 31, 2003, the subordinated units have a debit balance in Partners' Capital of approximately $39.9 million. The debit balance is the result of several different factors including: (i) a low initial capital balance in connection with the formation of the partnership as a result of a low carry-over book basis in the assets contributed to the Partnership at the date of formation, (ii) a significant net loss in 1999 and (iii) distributions to unitholders that have exceeded net income allocated to unitholders each period. Additionally, the capital balances of the common unitholders and the General Partner have increased periodically as additional units have been sold and as the General Partner has made additional capital contributions associated with those offerings. The subordinated unitholders are not required to make any additional contributions associated with those offerings of common units. No additional Subordinated Units were issued after the initial issuance.

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Issuance of Common Units

        We issued approximately 138,000 common units during the first quarter of 2004 in conjunction with the vesting of awards under our Long-Term Incentive Plan ("LTIP"). See Note 6 for additional discussion. In addition, the General Partner made a proportional two percent contribution.

Distributions

        On April 23, 2004, we declared a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and Class C common units. The distribution is payable on May 14, 2004, to unitholders of record on May 4, 2004, for the period January 1, 2004, through March 31, 2004. The total distribution to be paid is approximately $37.5 million, with approximately $35.0 million to be paid to our common unitholders and $0.7 million and $1.8 million to be paid to our general partner for its general partner and incentive distribution interests, respectively.

        On January 22, 2004, we declared a cash distribution of $0.5625 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid on February 13, 2004, to unitholders of record on February 3, 2004, for the period October 1, 2003, through December 31, 2003. The total distribution paid was approximately $35.2 million, with approximately $28.7 million paid to our common unitholders, $4.2 million paid to our subordinated unitholders and $0.7 million and $1.6 million paid to our general partner for its general partner and incentive distribution interests, respectively.

Contingent Equity Issuance

        In connection with the CANPET acquisition in July 2001, $26.5 million Canadian of the purchase price, payable in common units or cash at our option, was deferred subject to various performance objectives being met. These objectives were met as of December 31, 2003 and an increase to goodwill for this liability was recorded as of this date. The liability was satisfied on April 30, 2004. We issued approximately 385,000 common units and paid $6.5 million in cash to satisfy the obligation. The number of common units issued in satisfaction of the deferred payment was based upon $34.02 per share, the average trading price of our common units for the ten-day trading period prior to the payment date, and a Canadian dollar to U.S. dollar exchange rate of 1.35 to 1, the average noon-day exchange rate for the ten-day trading period prior to the payment date. In addition, $3.7 million in cash was paid for the distributions that would have been paid on the common units had they been outstanding since the effective date of the acquisition.

Private Placement of Series C Common Units

        In connection with the acquisition discussed in Note 11, the partnership issued 3,245,700 Class C Common Units for $30.81 per unit in a private placement completed on April 15, 2004. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million. The Class C Common Units are unlisted securities that are pari passu in voting and distribution rights with the Partnership's publicly traded Common Units. The Class C Common Units are similar in many respects to the Partnership's Class B Common Units. The Class C Units are convertible into Common Units upon approval by the holders of a majority of the Common Units. Beginning six months from the closing of the private placement, the Class C Unitholders may request that the Partnership call a meeting of its Common Unitholders to consider approval of the conversion of the Class C Units into Common Units. If the approval of the conversion is not obtained within 120 days of the request, the Class C Unitholders will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a Common Unit. If the approval of the conversion is not secured within 90 days after the end of the 120-day period, the distribution right increases to 115%.

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Note 6—Vesting of Unit Grants Under Long-Term Incentive Plan

        As of March 31, 2004, grants of approximately 681,000 restricted phantom units were outstanding under our LTIP. During the first quarter of 2004, approximately 326,000 phantom units vested. We paid cash in lieu of delivery of common units for approximately 104,000 of the phantom units and issued approximately 138,000 new common units (after netting for taxes) in connection with the remainder of the vesting.

        In addition, approximately 470,000 additional phantom units vested in May 2004. We paid cash rather than common units for approximately 202,000 of these phantom units and issued approximately 177,500 new common units (after netting for taxes) in connection with the remainder of that vesting.

        Under generally accepted accounting principles, we are required to recognize an expense when it is considered probable that the phantom unit grants will vest. During the first quarter of 2004, we recognized $4.2 million of compensation expense related to the LTIP units. This was comprised of approximately $1.1 million related to units that vested in May and for which partial satisfaction of service period requirements has been met and approximately $3.1 million related to the vesting of approximately 101,000 additional phantom units. Some of these units will vest at a distribution level of $2.30, subject to applicable continuing employment requirements, and some will vest with the passage of time. We have concluded this vesting is probable and have thus accrued for this obligation. At a distribution level of $2.50 to $2.69, approximately 95,000 additional units would vest. At the time it is considered probable that this distribution level will be met, the costs associated with the vesting of these additional units will be accrued. We anticipate that, after giving effect to the May vesting and related tax withholding and cash settlement, approximately 845,000 phantom units will be available under the plan for future grant and approximately 216,000 phantom units will remain outstanding. In accordance with the provisions of the LTIP and applicable NYSE standards, no more than approximately 611,000 phantom unit grants can be satisfied by delivery of common units.

Note 7—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 March 31, 2004, balance sheet includes assets of $24.2 million ($13.6 million current), liabilities of $24.7 million ($20.4 million current) and unrealized net losses deferred to Other Comprehensive Income ("OCI") of $15.0 million. Earnings for the three months ended March 31, 2004, include a gain of $10.0 million (including, $2.1 million, which was reclassified into earnings from OCI during the period).

        As of March 31, 2004, the total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the

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underlying commodity or payments of interest. During the three months ended March 31, 2004, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Of the $15.0 million net loss deferred in OCI at March 31, 2004, a net loss of $9.2 million will be reclassified into earnings in the next twelve months and the remainder by 2013. Since a portion of these amounts are based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

Commodity Price Risk Hedging

        We hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments utilized consist primarily of futures and option contracts traded on the NYMEX and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies. In accordance with SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," these derivative instruments are recognized in the balance sheet or earnings at their fair values. The majority of 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. At March 31, 2004, there was an unrealized loss of $9.1 million, deferred in OCI related to our commodity price risk activities. Approximately $8.5 million of the loss on these deferred positions will be reclassified into earnings in the next twelve months and the remainder by July 2006. Earnings for the three months ended March 31, 2004 include a net gain of $10.8 million (including $2.8 million, which was reclassified into earnings from OCI during the period). We have determined that our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133.

Controlled Trading Program

        Although we seek to maintain a position that is substantially balanced within our crude oil lease purchase activities, we may experience net unbalanced positions for short periods of time as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues. There were no open positions under this program at March 31, 2004 and 2003. The realized earnings impact related to these activities for the three months ended March 31, 2004, was a loss of approximately $0.1 million.

Interest Rate Risk Hedging

        At March 31, 2004, we have no open interest rate hedging instruments. However, there is approximately $5.8 million deferred in OCI that relates to instruments terminated and cash settled in 2003. The net deferred loss related to these instruments is being amortized into interest expense over the original terms of the terminated instruments (approximately fifty percent over three years and the remaining fifty percent over ten years). Approximately $0.4 million related to the terminated instruments has been reclassified into interest expense during the first quarter of 2004, and approximately $1.4 million will be reclassified for the entire year of 2004. In addition, earnings includes a loss of approximately $0.4 million that was reclassified out of OCI related to an instrument that matured in March 2004.

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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. Additionally, at times, a portion of our debt is denominated in Canadian dollars. At March 31, 2004, $3.7 million of our long-term debt was denominated in Canadian dollars ($4.9 million Canadian based on a Canadian dollar to U.S. dollar exchange rate of 1.31 to 1). All of these financial instruments are placed with what we believe to be large creditworthy financial institutions.

        At March 31, 2004, we had forward exchange contracts that allow us to exchange $2.0 million Canadian for approximately $1.5 million U.S. quarterly during 2004 and approximately $1.0 million Canadian for approximately $0.7 million U.S. quarterly during 2005 (based on a Canadian dollar to U.S. dollar exchange rate of 1.33 to 1 and 1.34 to 1, respectively). In addition, at March 31, 2004, we also had cross currency swap contracts for an aggregate notional principal amount of $23.0 million, effectively converting this amount of our U.S. dollar denominated debt to $35.6 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1). The notional principal amount reduces by $2.0 million U.S. in May 2004 and May 2005 and has a final maturity in May 2006 of $19.0 million U.S.

        The forward exchange contracts and forward extra option contracts qualify for hedge accounting as cash flow hedges and the cross currency swaps qualify for hedge accounting as fair value hedges, both in accordance with SFAS 133. Such derivative activity resulted in an unrealized loss of $0.2 million deferred in OCI related to our currency exchange rate cash flow hedges at March 31, 2004. The earnings impact related to our currency exchange rate fair value hedges was nominal for the three months ended March 31, 2004.

Note 8—Revenue Recognition Policy

        Following is a description of our revenue recognition policy:

        Gathering, Marketing, Terminalling and Storage Segment Revenues.     Revenues from crude oil and LPG sales are recognized at the time title to the product sold transfers to the purchaser, which occurs upon receipt of the product by the purchaser. All sales of crude oil and LPG are booked gross except in the case of barrel exchanges that are net settled. Terminalling and storage revenues, which are classified as Other revenues on the income statement, consist of (i) storage fees from actual storage used on a month-to-month basis; (ii) storage fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer on a given month; and (iii) terminal throughput charges to pump crude oil to connecting carriers. Revenues on storage are recognized ratably over the term of the contract. Terminal throughput charges are recognized as the crude oil exits the terminal and is delivered to the connecting crude oil carrier. Any throughput volumes in transit at the end of a given month are treated as third-party inventory and do not incur storage fees. All terminalling and storage revenues are based on actual volumes and rates.

        Pipeline Segment Revenues.     Pipeline margin activities primarily consist of the purchase and sale of crude oil shipped on our San Joaquin Valley system from barrel exchanges and buy/sell arrangements. Revenues associated with these activities are recognized at the time title to the product sold transfers to the purchaser, which occurs upon receipt of the product by the purchaser. Revenues for these transactions are recorded gross except in the case of barrel exchanges that are net settled. All of our pipeline margin activities revenues are based on actual volumes and prices. Revenues from pipeline tariffs and fees are associated with the transportation of crude oil at a published tariff as well as fees associated with line leases for committed space on a particular system that may or may not be utilized. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with line lease fees are recognized in the

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month to which the lease applies, whether or not the space is actually utilized. All pipeline tariff and fee revenues are based on actual volumes and rates.

Note 9—Commitments and Contingencies

Litigation

        Export License Matter.     In our gathering and marketing activities, we import and export crude oil from and to Canada. Exports of crude oil are subject to the short supply controls of the Export Administration Regulations ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") of the U.S. Department of Commerce. In 2002, we determined that we may have exceeded the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. We also conducted reviews of new and existing contracts and implemented new procedures and practices in order to monitor compliance with applicable laws regarding the export of crude oil to Canada. As a result, we subsequently submitted additional information to the BIS in October 2003 and May 2004 and intend to supplement that data to the extent applicable. At this time, we have received no indication whether the BIS intends to charge us with a violation of the EAR or, if so, what penalties would be assessed. As a result, we cannot estimate the ultimate impact of this matter.

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

Environmental

        We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover past releases that were previously unidentified. Although we maintain an inspection program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to any such environmental releases from our assets may substantially affect our business. At March 31, 2004, our reserve for environmental liabilities totaled approximately $6.8 million. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.

Other

        The occurrence of a significant event not fully insured 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) Pipeline Operations—engages in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; and (2) Gathering, Marketing, Terminalling and Storage Operations—engages in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets.

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In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow.

        We evaluate segment performance based on (i) segment profit, (ii) segment profit before segment general and administrative ("G&A") expenses and (iii) maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating expenses, and (iii) segment G&A expenses. Maintenance capital consists of capital expenditures required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives. Capital expenditures made to expand our existing capacity, whether through construction or acquisition, are not considered maintenance capital expenditures. Repair and maintenance expenditures associated with existing assets that do not extend the useful life or expand the operating capacity are charged to expense as incurred.

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(1)

Intersegment sales are conducted at arms length.

(2)

Segment 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 exist at that time. The proportional allocations by segment require judgment by management and will continue to be based on business activities that exist during each period.

(3)

Amounts related to SFAS 133 are included in revenues and impact segment profit and segment profit before segment G&A expenses.

(4)

The following table reconciles segment profit to consolidated net income (in millions):