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PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES 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 May 5, 2004, there were outstanding 57,724,722 Common Units, 1,307,190 Class B Common Units and 3,245,700 Class C Common 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") 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):

Note 11—Subsequent Events

Link Acquisition

        On April 1, 2004, we completed the acquisition of substantially all of the North American crude oil and pipeline operations of Link Energy LLC ("Link") for approximately $330 million, including $273 million of cash, the assumption of $49 million of liabilities and $8 million of transaction, closing and integration costs and other items. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions.

        The acquisition was funded with cash on hand, borrowings under a new $200 million 364-day credit facility and borrowings under our existing revolving credit facilities. The new credit facility contains a twelve-month term out option, exercisable at our election, at the end of the primary term, bears interest at a rate of LIBOR plus a margin ranging from ..625% to 1.25%, depending upon our credit rating, and

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includes essentially the same covenants as our existing credit facilities. On April 15, we completed the private placement of 3,245,700 units of Class C Common Units for $30.81 per unit to a group of institutional investors. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million and was used to reduce the balance outstanding under our existing revolving credit facilities. The partnership has committed to use net proceeds from future debt and equity offerings to retire or reduce the amount outstanding under the new $200 million 364-day credit facility.

        On April 2, 2004, the Office of the Attorney General of Texas delivered written notice to us that it was investigating the possibility that the acquisition of Link's assets might reduce competition in one or more markets within the petroleum products industry in the State of Texas. In connection with the Link purchase, both PAA and Link completed all necessary filings required under the Hart-Scott-Rodino Act, and the required 30-day waiting period expired on March 24, 2004 without any inquiry or request for additional information from the U.S. Department of Justice or the Federal Trade Commission. Representatives from the Antitrust and Civil Medicaid Fraud Division of the Office of the Attorney General of Texas indicated their investigation was prompted by complaints received from allegedly interested industry parties regarding the potential impact on competition in the Permian Basin area of West Texas. We understand that similar complaints have been received by the Federal Trade Commission, and that, consistent with federal-state protocols for conducting joint merger investigations, appropriate federal and state antitrust authorities will be coordinating their activities. We are cooperating fully with the antitrust enforcement authorities.

Cal Ven Acquisition

        On May 7, 2004 we completed the acquisition of the Cal Ven Pipeline System from Cal Ven Limited, a subsidiary of Unocal Canada Limited. The total purchase price was approximately $19 million, including transaction costs. The transaction was funded through a combination of cash on hand and borrowings under our revolving credit facilities. The Cal Ven Pipeline System is comprised of approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The system is located in northern Alberta and delivers crude oil into the Rainbow Pipeline System at Utikuma. The Rainbow Pipeline System then transports the crude south to the Edmonton market, where it can be used in local refineries or shipped on connecting pipelines to the U.S. market.

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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 Delaware limited partnership (the "Partnership") formed in September of 1998. 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. We are 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 liquified petroleum gas and other petroleum products collectively as "LPG." We own an extensive network in the United States and Canada of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs.

        In order to better understand the financial statements discussed herein, it is important to understand the basic nature of our two operating segments as well as the magnitude of the impact of our acquisition program. Our operations are conducted primarily in Texas, Oklahoma, California, Louisiana and the Canadian provinces of Alberta and Saskatchewan and consist of two operating segments: (i) Pipeline Operations and (ii) Gathering, Marketing, Terminalling and Storage Operations ("GMT&S"). Our revenues from pipeline operations are generally derived from the transportation of crude oil for a fee and leases of pipeline capacity to third parties, as well as from certain barrel exchanges and buy/sell arrangements. Our revenues from gathering and marketing activities reflect the sale of gathered and bulk-purchased crude oil and LPG plus the sale of additional barrels through buy/sell arrangements entered into to enhance the margins of the gathered and bulk-purchased volumes. Our revenues from terminalling and storage operations are a combination of storage and throughput charges to third parties and serve to provide a countercyclical balance to our gathering and marketing activities. In addition, a significant portion of our tankage is used to support our arbitrage activities and enables us to enhance our margins in a contango market (when the oil prices for future deliveries are higher than the current prices) or when the market switches from contango to backwardation (when the oil prices for future deliveries are lower than the current prices). We discuss the fundamental drivers of each of these operating segments in greater detail below in our "Analysis of Operating Segments." The significant impact of our acquisition program on our reported financial results is also discussed under "Acquisitions" immediately below.

Acquisitions

        We completed several acquisitions during 2004 and 2003 that have impacted the results of operations and liquidity discussed herein. The following acquisitions were accounted for, and the purchase prices were allocated, in accordance with SFAS 141 "Business Combinations." Our ongoing acquisition activity is discussed further in "Outlook" below.

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 principal assets of the 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

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transportation routes for crude oil shipped into the Midwestern U.S. and delivered to several refineries and other pipelines.

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

2003 Acquisitions

        During 2003, we completed ten acquisitions for aggregate consideration of approximately $159.5 million. The aggregate consideration includes cash paid, estimated transaction costs, assumed liabilities and estimated near-term capital costs. The acquisitions were initially financed with borrowings under our credit facilities, which were subsequently repaid with a portion of the proceeds from our equity issuances and the issuance of senior notes. The businesses acquired during 2003 impacted our results of operations subsequent to the effective date of each acquisition as indicated below. 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 $0.5 million that was allocated to goodwill and other intangible assets and $4.7 million associated with crude oil linefill and working inventory, the remaining aggregate purchase price was allocated to property and equipment. The following table details our 2003 acquisitions (in millions):

(1)

Consists of an 8.8% undivided interest.

(2)

Includes a 33.3% interest in Atchafalaya Pipeline L.L.C.

(3)

Includes two acquisitions each for 33.3% interests in Atchafalaya Pipeline L.L.C.

Critical Accounting Policies and Estimates

        The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities, at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Although we believe these estimates are reasonable, actual results could differ from these estimates. The critical accounting policies that we have identified are discussed below.

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Depreciation, Amortization and Impairment of Long-Lived Assets

        We calculate our depreciation and amortization based on estimated useful lives and salvage values of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

        Additionally, we assess our long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in our business plans, a change in the extent or manner in which a long-lived asset is being used or in its physical condition, or a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge would be recorded for the excess of the carrying value of the asset over its fair value. Determination as to whether and how much an asset is impaired would necessarily involve numerous management estimates. Any impairment reviews and calculations would be based on assumptions that are consistent with our business plans and long-term investment decisions. Historically, these assessments have not resulted in an impairment to the carrying value of our long-lived assets. An impairment in the future could have a negative effect on our liquidity and capital resources because such impairment is likely to reflect a reduction in the asset's ability to generate cash flow.

Allowance for Doubtful 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 and consider the 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.

Purchase and Sales Accruals

        We routinely make accruals based on estimates for certain components of our revenues and cost of sales due to the timing of compiling billing information, receiving third-party information and reconciling our records with those of third parties. Where applicable, these accruals are based on nominated volumes expected to be purchased, transported and subsequently sold. Uncertainties involved in these estimates include levels of production at the wellhead, access to certain qualities of crude oil, pipeline capacities and delivery times, utilization of truck fleets to transport volumes to their destinations, weather, market conditions and other forces beyond our control. Historically, less than 2% of total revenues have been recorded using estimates. Accordingly, a variance from this estimate of 10% would impact total revenues by less than 1%. We do not believe the resolution of these uncertainties will have a material impact on our reported results of operations or financial condition.

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        In situations where we are required to make mark-to-market estimates pursuant to SFAS 133, the estimates of gains or losses at a particular period end do not reflect the end results of particular transactions, and will most likely not reflect the actual gain or loss at the conclusion of a transaction. We reflect estimates for these items based on our internal records and information from third parties. A portion of the estimates we use are based on internal models or models of third parties because they are not quoted on a national market. Additionally, values may vary among different models due to a difference in assumptions applied such as the estimate of prevailing market prices, volatility, correlations and other factors and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Less than 1% of total revenues are based on estimates derived from these models. We believe our estimates for these items are reasonable, but there is no assurance that actual amounts will not vary significantly from estimated amounts.

Liability and Contingency Accruals

        We accrue reserves for contingent liabilities including, but not limited to, environmental remediation, insurance claims and potential legal claims. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, costs of medical care associated with worker's compensation insurance claims, and the possibility of existing legal claims giving rise to additional claims. Our estimates for liability and contingency accruals are increased or decreased as additional information is obtained or resolution is achieved. We also make accruals for potential payments under our Long-Term Incentive Plan ("LTIP") when we determine that vesting of the units is probable. The aggregate amount of the actual charge to expense will be determined by the unit price on the date vesting occurs (or, in some cases, the average unit price for a range of dates) multiplied by the number of units, plus our share of associated employment taxes. Uncertainties involved in this accrual include whether or not we actually achieve the specified performance requirements, the actual unit price at time of settlement and the continued employment of personnel subject to the vestings. We believe our estimates for these items are reasonable, but there is no assurance that actual amounts will not vary significantly from estimated amounts.

Determination of Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets

        In conjunction with each acquisition, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. We also estimate the amount of transaction costs that will be incurred in connection with each acquisition. As additional information becomes available, we may adjust the original estimates within a short time period subsequent to the acquisition. In addition, in conjunction with the adoption of SFAS 141, we are required to recognize intangible assets separately from goodwill. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment. The impairment testing entails estimating future net cash flows relating to the asset, based on management's estimate of market conditions including pricing, demand, competition, operating costs and other factors. Intangible assets with finite lives are amortized over the estimated useful life determined by management. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, contracts, and industry expertise involves professional judgment and is ultimately based on acquisition models and management's assessment of the value of the assets acquired and, to the extent available, third party assessments. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. We believe our estimates for these items are

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reasonable, but there is no assurance that actual amounts will not vary significantly from estimated amounts.

        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 abandoned. 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.

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 barrel exchanges and buy/sell arrangements utilizing our proprietary pipelines; 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.

        For the three months ended March 31, 2004, we reported consolidated net income of $31.0 million on total revenues of $3.8 billion compared to net income for the same period in 2003 of $24.4 million on total revenues of $3.3 billion. Included in the results of operations for the three months ended March 31, 2004 and 2003, are selected items that impact the comparability between periods, which are discussed further below.

        In evaluating our operating results, management considers the effects of selected items that they believe impact the comparability of our financial results between periods. Because management considers an understanding of these selected items to be material to its evaluation of our operating results and prospects, we have presented the table below as additional information that may be helpful to your understanding of our financial results. You should also be aware that the items presented below do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions and numerous other factors. Because management believes these types of variations to be directly related to the actual operating activities for the periods presented, they are not separately identified below. Instead, appropriate discussions of these types of operating variances and their impact on reported results between comparative periods are included in the discussion and analysis of the segment's

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performance for such period. In considering the information included in the table below, you should also refer to the more complete discussion of each of these items immediately following the table.

        The following is a discussion of each of the selected items that impacted our results of operations. Further discussion of each of these items is included in the applicable portion of the results of operations discussion.

        Noncash Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" Adjustment—SFAS 133 requires that changes in derivative instruments' fair value be recognized currently in earnings unless specific cash flow hedge accounting criteria are met, in which case, changes in fair value are deferred to Other Comprehensive Income, or "OCI," and reclassified into earnings when the underlying transaction affects earnings. Accordingly, changes in fair value are included in earnings in the current period for (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items. We believe that the majority of instruments we are required to mark-to-market at the end of each quarterly period pursuant to SFAS 133 nonetheless serve as economic hedges (even though they do not meet SFAS 133 hedge definition requirements) in that they offset future physical positions or anticipated cash flow related to our assets attributable to a future period. All of our derivative transactions except our controlled trading program fall under our Enterprise Level Program, which has the objective of hedging exposures arising from our core businesses. 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, because these adjustments represent only the derivative side of these transactions and do not take into account the offsetting physical position or cash flow exposure associated with our assets. 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 be negated by offsetting gains or losses on the underlying physical transaction or cash flow of the asset in future periods. The extent of the offset will depend on multiple factors, including the price indices of the underlying contracts and hedges, utilization of our assets, and various other factors. Accordingly, when we evaluate our results internally for performance against expectations, public guidance and trend analysis, we exclude the noncash, mark-to-market impact of SFAS 133. 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. We reported SFAS 133 gains of $7.5 million and $0.9 million in revenues, for the three months ending March 31, 2004 and 2003, respectively.

        Our first quarter 2004 SFAS 133 gain includes three primary components, two positive amounts totaling $9.1 million and one negative amount for $1.6 million. The details of these three components are as follows:

•

A gain of approximately $2.0 million relates to our Canadian operations, primarily due to physical hedges that do not consistently meet the 80% correlation to be considered a hedge for accounting purposes. Approximately $1.7 million of this gain is related to a reversal of a noncash mark-to-market loss recognized in prior periods.

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•

A gain of approximately $7.1 million is attributable primarily to hedges of cash flows associated with tankage assets that are accomplished through futures contracts and options contracts. Because these arrangements will not necessarily result in physical delivery, they are not eligible for hedge accounting treatment under SFAS 133. The bulk of the current period impact is largely due to increased strength in the backwardation in the futures market and the balance is generally attributable to a reversal of a noncash mark-to-market loss recognized in prior periods.



•

A loss of $1.6 million is related to a contractual arrangement where the counterparty requires that we cancel the physical contracts and net settle the balance due. Since this arrangement can be cash settled, transactions under this arrangement are not eligible for hedge accounting treatment under SFAS 133.

        Long-Term Incentive Plan charge—Under generally accepted accounting principles, we are required to recognize an expense when vesting of LTIP units becomes probable as determined by management. Our results of operations include a charge of $4.2 million in the three months ended March 31, 2004. This charge is comprised of two components as follows:

•

Approximately $1.1 million related to approximately 470,000 phantom units that vested in May 2004. We had previously concluded at December 31, 2003, that these units were probable of vesting and had accrued a portion of the related obligation at that time. The additional first quarter charge relates to the amortization of service period requirements and adjustments to the assumptions used in our estimate.



•

Approximately $3.1 million of the charge related to an additional approximately 100,000 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.

Analysis of Operating Segments

        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. Our current estimate of maintenance capital expenditures for the year 2004 is approximately $16.8 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

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analysis is provided, except on an annual basis. The following table reflects our results of operations for each segment:

(1)

Revenues and purchases include intersegment amounts.

(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 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 and impact segment profit and segment profit before segment G&A expenses.

Pipeline Operations

        As of March 31, 2004, we owned and operated approximately 7,200 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 on our proprietary pipelines (collectively referred to as "tariff activities"), as well as barrel exchanges and buy/sell arrangements (collectively referred to as "pipeline 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. These transactions are conducted at published tariff rates and eliminated in consolidation. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The segment profit before segment G&A 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

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charged as well as the fixed and variable field costs of operating the pipeline. Segment profit before segment G&A from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

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

(1)

Revenues and purchases include intersegment amounts.

(2)

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

(3)

Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period. Volumes are presented in this manner to allow for relevant comparisons to revenues generated and segment profit, and is necessary to accurately calculate statistics on a per barrel basis.

(4)

Capline volumes averaged approximately 160,000 barrels per day for March 2004, which is the period we owned the system. This calculates to approximately 54,000 barrels per day over the first quarter of 2004.

        Total average daily volumes transported were approximately 1,048,000 barrels per day and 818,000 barrels per day for the three months ended March 31, 2004 and 2003, respectively. The increase primarily relates to our tariff activities. As discussed above, we have completed a number of acquisitions during 2004

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and 2003 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:

(1)

Volumes associated with acquisitions represent weighted average daily amounts for the number of days we actually owned the assets over the total days in the period. Volumes are presented in this manner to allow for relevant comparisons to revenues generated and segment profit, and is necessary to accurately calculate statistics on a per barrel basis.

        Average daily volumes from our tariff activities increased 244,000 barrels per day to approximately 976,000 barrels per day, compared to approximately 732,000 barrels per day for the prior year quarter. Approximately 238,000 barrels per day of the increase in the current year quarter is due to volumes transported on the pipelines acquired in 2004 and 2003. Volumes on all other pipeline systems increased by approximately 6,000 barrels per day to approximately 724,000 barrels per day.

        Total revenues from our pipeline operations were approximately $189.3 million and $169.0 million for the three months ended March 31, 2004 and 2003, respectively. Strong tariff activities results, specifically the inclusion of revenues from pipelines acquired after the first quarter of 2003, accounted for $13.2 million of the increase. Additionally, our margin activities increased by approximately $7.1 million in the first quarter of 2004. This increase was related to higher average prices on activity on our San Joaquin Valley ("SJV") gathering system in the 2004 period as compared to the 2003 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 segment profit. Volumes transported on the SJV system have decreased from the 2003 period. This is primarily related to a normalizing of volumes transported in the first quarter of 2004 as the first quarter of 2003 included additional shipments that typically move on other pipelines. These volumes shifted to the SJV system because of maintenance on a refinery.

        Revenues from our tariff activities increased approximately 39% or $13.2 million. The following table reflects our revenues from our tariff activities by year of acquisition for comparison purposes:

(1)

Revenues include intersegment amounts.

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        The increase in the first quarter of 2004 is predominately related to the inclusion of $11.0 million of revenues from the businesses acquired in 2004 and 2003. Revenues from pipeline systems acquired in 2003 have increased to $7.7 million from $1.2 million. The increase is primarily the result of the inclusion in the first quarter of 2004 of several pipeline systems that were acquired after or during the first quarter of 2003. See "Acquisitions." Revenues from all other pipeline systems increased approximately $3.4 million to $36.0 million. This increase resulted principally from (i) a net increase of $1.7 million resulting from increased volumes on our Basin and Permian Basin Pipeline Systems partially offset by the loss of revenue from our Rancho Pipeline System, which ceased operations in March 2003 and (ii) increased revenues from our Canadian operations of $1.5 million resulting primarily from a decrease in the Canadian dollar to U.S. dollar exchange rate to an average rate of 1.32 to 1 for the three months ended March 31, 2004, from an average rate of 1.51 to 1 for the three months ended March 31, 2003. This increase excludes the impact of the recent acquisition of the South Sask Pipeline System, which is included in the 2004 acquisitions amount discussed above.

        As a result of these factors, our pipeline operations segment profit before segment G&A expenses increased $8.4 million or 34%, to approximately $33.2 million for the quarter ended March 31, 2004, from $24.8 million for the prior year period. This includes an increase in field operating expenses to $19.4 million in the 2004 period from $13.5 million in the 2003. This increase is predominately related to our continued growth, primarily from acquisitions, coupled with higher utility costs as well as $0.1 million related to the accrual made for the probable vesting of unit grants under our LTIP. In addition, segment profit before segment G&A includes a $0.7 million favorable impact resulting from the decrease in the average Canadian dollar to U.S. dollar exchange rate for the 2004 period as compared to the 2003 period.

        Segment general and administrative expenses increased approximately $3.1 million between comparable periods, primarily as a result of a $1.7 million accrual related to the probable vesting of unit grants under our LTIP. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has continued to increase in the 2004 period as our pipeline operations have grown. Including the impact of the items discussed above, segment profit was approximately $25.5 million in the first quarter of 2004, an increase of 26% as compared to the $20.2 million reported for the quarter ended March 31, 2003. Segment profit includes a $0.6 million favorable impact resulting from the decrease in the average Canadian dollar to U.S. dollar exchange rate for the 2004 period as compared to the 2003 period.

Gathering, Marketing, Terminalling and Storage Operations

        Our revenues from gathering and marketing activities primarily reflect the sale of gathered and bulk-purchased crude oil and LPG volumes plus the sale of additional barrels exchanged through buy/sell arrangements entered into to supplement the margins of the gathered and bulk-purchased volumes. Because our profitability is a function of the difference between the revenues we receive for selling crude and LPG volumes and the cost of purchasing these volumes, increases or decreases in our revenues are not necessarily indicative of increases or decreases in our profitability. Prices we receive for selling our volumes and costs we incur in buying our volumes are affected by overall levels of supply and demand for crude oil and LPG and fluctuations in the market-related pricing indices. In order to evaluate the performance of this segment, management focuses on the following metrics: (i) segment profit before segment G&A, (ii) segment profit, (iii) crude oil lease gathered volumes and LPG sales volumes and (iv) segment profit per barrel calculated on these volumes.

        As of March 31, 2004, we owned and operated approximately 26.3 million barrels of above-ground crude oil terminalling and storage facilities, including a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to as the Cushing Interchange, is one of the largest crude oil market hubs in the United States and the designated delivery point for New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling." Approximately 11.0 million

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barrels of our 26.3 million barrels of tankage is used primarily in our Gathering, Marketing, Terminalling and Storage Operations and the balance is used in our Pipeline Operations segment. On a stand alone basis, segment profit before segment G&A from terminalling and storage activities is dependent on the throughput of volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. Our terminalling and storage activities are integrated with our gathering and marketing activities and the level of tankage that we allocate for our arbitrage activities (and therefore not available for lease to third parties) varies throughout crude oil price cycles. This integration enables us to use our storage tanks in an effort to counter-cyclically balance and hedge our gathering and marketing activities. 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 (when 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 this 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 flows.

        During the first quarter of 2004, market conditions were favorable as the market was in relatively strong backwardation and experienced periods of volatility. The NYMEX benchmark price of crude ranged from $38.50 to $32.20 during the quarter. In comparison, the market conditions in the first quarter of 2003 were exceedingly favorable as there was extreme volatility and steep backwardation throughout the quarter. During the first quarter of 2003, the NYMEX benchmark price of crude ranged from $39.99 to $26.30. The following table sets forth our operating results from our Gathering, Marketing, Terminalling and Storage Operations segment for the comparative periods indicated:

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(1)

Revenues and purchases and related costs include intersegment amounts.

(2)

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

(3)

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

(4)

Volumes associated with acquisitions represent weighted averaged daily amounts for the number of days we actually owned the assets over the total days in the period. Volumes are presented in this manner to allow for relevant comparisons to revenues generated and segment profit, and is necessary to accurately calculate statistics on a per barrel basis.

(5)

Prior period volumes have been adjusted for consistency of comparison between years. Sales reflect only third party volumes.

        In addition to market conditions and our hedging activities, the primary drivers of the performance of our gathering, marketing, terminalling and storage operations segment are crude oil lease gathered volumes and LPG sales volumes. Crude oil bulk purchase volumes are not considered a driver as they are primarily used to enhance margins of lease gathered barrels. For the quarter ended March 31, 2004, we gathered from producers, using our assets or third-party assets, approximately 460,000 barrels of crude oil per day, an increase of 6% over similar activities in the first quarter of 2003. Also during the quarter, we marketed approximately 59,000 barrels per day of LPG, an increase of approximately 9% over the approximately 54,000 barrels per day marketed in the first quarter of 2003. Segment profit per barrel calculated on these volumes and including the items impacting comparability for the quarters ended March 31, 2004 and 2003, was $0.59 per barrel and $0.55 per barrel, respectively.

        Revenues from our gathering, marketing, terminalling and storage operations were approximately $3.6 billion and $3.1 billion for the quarters ended March 31, 2004 and 2003, respectively. Revenues and purchases for 2004 were impacted by higher average prices and higher crude oil lease gathering volumes in the 2004 period as compared to the 2003 period. The average NYMEX price for crude oil was $35.21 per barrel and $33.87 per barrel for the first quarter of 2004 and 2003, respectively.

        In both periods, we benefited from the backwardated market structure and volatility. In addition, our increased crude oil lease gathered volumes and LPG sales volumes in the 2004 period contributed to an increase in segment profit before segment G&A expenses. Also included in our results for both periods are

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selected items that we believe impact the comparability between periods, resulting in an overall increase in segment profit before G&A expenses, and are as follows:

        Segment profit before segment G&A expenses increased approximately $6.7 million to $39.5 million in the first quarter of 2004. This increase was primarily related to the impact of the selected items impacting comparability included in the table above. Also, field operating expenses decreased to approximately $18.9 million in the current period from $19.6 million in the prior year period. This decrease is primarily related to lower expenses associated with maintenance projects in 2004 as compared to 2003, coupled with a shift in overhead costs to our pipeline operations segment as that part of our business grows. This decrease is partially offset by the inclusion of the $0.4 million LTIP charge in the 2004 period as shown above. In addition, segment profit before G&A for the first quarter of 2004 includes a net approximately $2.4 million favorable impact from the decrease in the Canadian dollar to U.S. dollar exchange rate in the 2004 period as compared to the 2003 period.

        Segment G&A expenses increased to $11.4 million in the current period from $8.5 million in the 2003 period. The increase is primarily related to the inclusion of the $2.0 million LTIP charge in the 2004 period, as shown above, but also includes approximately $0.4 million of an unfavorable impact from the decrease in the Canadian dollar to U.S. dollar exchange rate and increased costs resulting from our continued growth. The current quarter segment profit of $28.1 million includes $5.1 million related to the selected items impacting comparability listed above.

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Other Expenses

Depreciation and Amortization

        Depreciation and amortization expense was $13.1 million for the three months ended March 31, 2004, compared to $10.9 million for the three months ended March 31, 2003. The increase relates primarily to the assets from our first quarter 2004 acquisition and our various 2003 acquisitions being included for the full quarter in 2004 versus only a part or none of the quarter in 2003. Additionally, several capital projects were completed during mid-to-late 2003 that were not included in first quarter 2003 depreciation expense. Amortization of debt issue costs was $0.5 million and $1.0 million in the first quarter of 2004 and 2003, respectively.

Interest Expense

        The amount of interest expense we recognize is primarily impacted by our average debt balances, the level and maturity of fixed rate debt and interest rates associated therewith, market interest rates and our interest rate hedging activities on floating rate debt. During the first quarter of 2004, our average debt balance was approximately $599 million. This balance consisted of fixed rate senior notes with a face amount totaling $450 million and borrowings under our revolving credit facilities averaging $149 million. During the comparable 2003 period, our average debt balance was approximately $527 million and consisted of fixed rate senior notes with a face amount of $200 million and borrowings under our revolving credit facilities of $327 million. The higher average debt balance in the 2004 period was primarily related to the portion of our acquisitions, that were not refinanced with equity. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity.

        During the fourth quarter of 2003, we refinanced our senior secured credit facilities with new senior unsecured credit facilities, issued $250 million of ten year senior unsecured notes and terminated interest rate hedging instruments with notional amounts totaling $150 million. The termination of these instruments was made in connection with the issuance of the ten year notes. The net result of the changes to our debt structure and our interest rate hedging instruments was an increase in the average amount of fixed rate debt outstanding in the first quarter of 2004 to approximately 75% as compared to approximately 57% in the first quarter of 2003. The new senior unsecured credit facilities reduced the interest rate on our credit facilities by approximately 100 basis points compared to the senior secured facility. In addition, during these two periods the average three-month LIBOR rate declined to 1.1% in 2004 from 1.3% in 2003.

        The net impact of the items discussed above was an increase in interest expense in the first quarter of 2004 of approximately $0.3 million to $9.5 million. The higher average debt in the 2004 period resulted in additional interest expense of approximately $1.1 million, while at the same time our commitment and other fees decreased by approximately $0.8 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 6.1% during both periods.

Outlook

        This "Outlook" section and the section captioned "Forward Looking Statements and Associated Risks" identify certain matters of risk and uncertainty that may affect our financial performance and results of operations in the future.

        Ongoing Acquisition Activities.    Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstream crude oil assets. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. We can give no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.

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        Link Energy LLC Acquisition.    On April 1, 2004, we completed the acquisition of the North American crude oil and pipeline operations of Link Energy LLC (the "Link acquisition") for approximately $330 million, including $273 million of cash, the assumption of $49 million of liabilities and $8 million of transaction, closing and integration costs and other items. The completion and integration of this acquisition will impact our operating results beginning in the second quarter of 2004. We anticipate that the assets acquired in the acquisition will generate a baseline cash flow from operations of approximately $6.25 million per quarter or approximately $25.0 million annually. In addition, we believe that we will realize annual cost savings and synergies of approximately $20.0 million to $30.0 million that are expected to be phased in over an 18 month period as the business is fully integrated. However, we also anticipate certain one-time expense items in the initial six to nine month period as a result of integration costs, as well as, costs associated with regulatory requirements as we perform activities to bring the assets up to our operating standards and to comply with regulatory requirements. These costs will have a negative impact in the short-term on our baseline projection for the acquisition.

Liquidity and Capital Resources

Liquidity

        Cash generated from operations and our credit facilities are our primary sources of liquidity. At March 31, 2004, we had a working capital deficit of approximately $72.5 million, approximately $433.5 million of availability under our committed revolving credit facilities and $200.0 million of unused capacity under our uncommitted hedged inventory facility. Usage of the credit facilities is subject to compliance with covenants. We believe we are currently in compliance with all covenants.

        As discussed above, we closed the Link acquisition on April 1, 2004. The acquisition was funded with cash on hand, borrowings under a new $200 million, 364-day credit facility and borrowings under our existing revolving credit facilities. The new credit facility contains a twelve-month term out option, exercisable at our election, at the end of the primary term and bears interest at a rate of LIBOR plus a margin ranging from .625% to 1.25%, depending on our credit rating. On April 15, we completed the private placement of 3,245,700 units of Class C Common Units for $30.81 per unit to a group of institutional investors. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, was approximately $101 million, and was used to reduce the balance outstanding under our existing revolving credit facilities. The Partnership has committed to use net proceeds from future debt and equity offerings to retire or reduce the amount outstanding under the new $200 million 364-day credit facility. Subsequent to these activities, on April 30, 2004, we had outstanding long-term debt of approximately $876.1 million, approximately $441.7 million of availability under our committed revolving credit facilities and $149.9 million of unused capacity under our uncommitted hedged inventory facility.

Capital Requirements

        We have made and will continue to make capital expenditures for acquisitions, expansion capital and maintenance capital. Historically, we have financed these expenditures primarily with cash generated by operations, credit facility borrowings, the issuance of senior unsecured notes and the sale of additional common units.

        We expect to spend approximately $103.2 million on expansion capital projects during 2004. This includes our original estimate of expansion capital, newly announced projects and expansion capital

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associated with the Link acquisition. Our 2004 expansion capital projects include the following notable projects with the estimated cost for the entire year.