NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Organization and Accounting Policies

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

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

Note 2—Acquisitions and Dispositions

The following acquisitions made in 2003 did not have a material effect on either our financial position, results of operations or cash flows, either individually or in the aggregate. The cash portion of these acquisitions was funded from cash on hand and borrowings under our revolving credit facility. The entire purchase price of each acquisition was allocated to property and equipment.

Iraan to Midland Pipeline System

In June 2003, the Partnership acquired the Iraan to Midland Pipeline System from a unit of Marathon Ashland Petroleum LLC (“MAP”) for aggregate consideration of approximately $17.4 million. The Iraan to Midland Pipeline System is a 16-inch, 95-mile mainline crude oil pipeline that originates in Iraan, Texas and terminates in Midland, Texas. At Midland, the system has the ability to deliver crude oil to our Basin Pipeline System and to the Mesa Pipeline System. In 2002, the Iraan to Midland Pipeline System delivered approximately 21,000 barrels per day of crude oil. The effective date of the transaction is June 30, 2003 and the results of operations and assets have been included in our consolidated financial statements and our pipeline operations since that time. The aggregate purchase price included $13.6 million in cash, approximately $3.6 million associated with the satisfaction of outstanding claims for accounts receivable and inventory balances, and approximately $0.2 million of estimated transaction costs.

South Louisiana Assets

In June 2003, we completed the acquisition of a package of terminalling and gathering assets from El Paso Corporation for approximately $10.8 million, including transaction costs. These assets are located in southern Louisiana and include various interests in five pipelines and gathering systems and two terminal facilities. These assets complement our existing activities in south Louisiana and we believe will help leverage our exposure to

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the growing volume of crude oil and condensate production from the Gulf of Mexico. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since June 1, 2003.

Alto Storage Facility

In June 2003, we completed the acquisition of an underground LPG storage facility from Ohio-Northwest Development, Inc. for approximately $8.1 million, including transaction costs and assumed liabilities. The underground facility, which is located in Alto, Michigan, is currently capable of storing over 38 million gallons of LPG. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our gathering, marketing, terminalling and storage operations segment since June 1, 2003. This storage facility further supports the expansion of our LPG business in Canada and the northern tier of the United States.

Mesa Pipeline System

In May 2003, we completed the acquisition of an 8.8% undivided interest in the Mesa Pipeline System from Unocal Corporation for approximately $2.9 million, including transaction costs. The system is located in the Permian Basin in West Texas, originating at Midland and terminating at Colorado City, and serves to complement our Basin Pipeline System. As a result of this transaction, we will have access to a net capacity of approximately 28,000 barrels of crude oil per day on the system. This system is operated by an affiliate of ChevronTexaco. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since May 5, 2003.

Iatan Gathering System

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

Red River Pipeline System

In February 2003, we completed the acquisition of a 347-mile crude oil pipeline from BP Pipelines (North America) Inc. for approximately $19.3 million, including transaction costs. The system originates at Sabine in East Texas and terminates near Cushing, Oklahoma. The system also includes approximately 695,000 barrels of crude oil storage capacity. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since February 1, 2003. This pipeline complements our existing assets in East Texas and, upon completion of a planned interconnect, will provide another direct mainline connection to our Cushing Terminal.

Shutdown of Rancho Pipeline System

We acquired the Rancho Pipeline System in conjunction with the acquisition of several other West Texas assets from Shell Pipeline Company, LP and Equilon Enterprises, LLC in August of 2002. The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, terminated in March 2003. Upon termination, the agreement required the owners to take the pipeline system, in which we owned an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not

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accept nominations for movements after February 28, 2003. This shutdown was contemplated at the time of the acquisition and was accounted for under purchase accounting in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 141 “Business Combinations.” The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. In June 2003, we completed transactions whereby we transferred all of our ownership interest in approximately 240 miles of the total 458 miles of the pipeline in exchange for $4 million and approximately 500,000 barrels of crude oil tankage in West Texas. The balance of the pipeline system is subject to an option to purchase by a third party. We are currently in discussions for the pipe to be salvaged in the event that the option to purchase is not exercised. No gain or loss has been recorded on the shutdown of the Rancho System or these transactions.

Note 3—Accounts Receivable

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

At June 30, 2003 approximately 98% of our net accounts receivable classified as current were less than 60 days past the scheduled invoice date. Our allowance for doubtful accounts receivable classified as current totaled $3.2 million, representing 27% of all receivable balances greater than 60 days past the scheduled invoice date. At June 30, 2003 approximately $0.9 million of net accounts receivable were classified as long-term. Our allowance for doubtful accounts receivable classified as long-term totaled $5.0 million, representing 85% of all long-term receivable balances.

Note 4—Debt

During the six months ended June 30, 2003 we had net borrowings under our revolving credit facilities of approximately $29.1 million, including borrowings for a scheduled maturity payment of $7.0 million on our senior secured term loan. At June 30, 2003, we have classified $10 million of term loan maturities due in the next twelve months as long term due to our intent and ability to refinance those maturities using the revolving credit facilities. At June 30, 2003 our total long-term debt balance was approximately $526.5 million and total availability under our long-term revolving credit facilities was approximately $403.1 million (net of $10.0 million to refinance term loan maturities due in the next twelve months).

Note 5—Partners’ Capital and Distributions

Distributions

On July 25, 2003, we declared a cash distribution of $0.55 per unit on our outstanding common units, Class B common units and subordinated units. The distribution is payable on August 14, 2003, to unitholders of record on August 4, 2003, for the period April 1, 2003, through June 30, 2003. The total distribution to be paid is approximately $30.6 million, with approximately $23.2 million to be paid to our common unitholders, $5.5 million to be paid to our subordinated unitholders and $0.6 million and $1.3 million to be paid to our general partner for its general partner and incentive distribution interests, respectively. The distribution is in excess of the minimum quarterly distribution specified in the partnership agreement.

On April 24, 2003, we declared a cash distribution of $0.55 per unit on our outstanding common units, Class B common units and subordinated units. The distribution was paid on May 15, 2003, to unitholders of record on

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May 5, 2003, for the period January 1, 2003, through March 31, 2003. The total distribution paid was approximately $30.6 million, with approximately $23.2 million paid to our common unitholders, $5.5 million paid to our subordinated unitholders and $0.6 million and $1.3 million paid to our general partner for its general partner and incentive distribution interests, respectively. The distribution was in excess of the minimum quarterly distribution specified in the partnership agreement.

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

Equity Offering

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

Note 6—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 June 30, 2003, balance sheet includes assets of $17.5 million ($13.5 million current), liabilities of $22.9 million ($6.5 million current) and related unrealized net losses deferred to Other Comprehensive Income (“OCI”) of $7.5 million. Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet. In addition, revenues for the six months ended June 30, 2003, included a noncash gain of $1.1 million ($2.1 million noncash gain before the reversal of the prior period fair value adjustment related to contracts that settled during the current period) resulting from (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that is not highly effective in offsetting changes in cash flows of hedged items.

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As of June 30, 2003, the total amount of deferred net losses recorded in OCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. During the six months ended June 30, 2003 and 2002, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Of the $7.5 million net loss deferred to OCI at June 30, 2003, a gain of $4.6 million will be reclassified to earnings in the next twelve months and the remainder by May 2006. Since these amounts are based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

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

Commodity Price Risk Hedging

We hedge our exposure to price fluctuations with respect to crude oil and LPG in storage, and expected purchases, sales and transportation of these commodities. The derivative instruments utilized consist primarily of futures and option contracts traded on the New York Mercantile Exchange and over-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies. In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” these derivative instruments are recognized in the balance sheet or earnings at their fair values. The majority of our commodity price risk derivative instruments qualify for hedge accounting as cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred into OCI and recognized in revenues or cost of sales and operations in the periods during which the underlying physical transactions occur. We have determined that our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133. At June 30, 2003 and 2002, there was a gain of $6.3 million and a gain of $0.1 million, respectively, deferred in OCI related to our commodity price risk activities. The amount included in earnings due to changes in the fair value of derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective for the six months ended June 30, 2003 and 2002, was a gain of $1.3 million and a loss of $1.7 million, respectively.

Controlled Trading Program

From time to time, we experience net unbalanced positions as a result of production and delivery variances associated with our lease purchase activities. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, we engage in a controlled trading program for up to 500,000 barrels. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues. There were no open positions under this program at June 30, 2003. The realized earnings impact related to these derivatives for the six months ended June 30, 2003 and 2002 was a loss of $0.1 million and $0.2 million, respectively.

Interest Rate Risk Hedging

We utilize various products, such as interest rate swaps, collars and treasury locks, to hedge interest obligations on specific debt issuances, including anticipated debt issuances. During the first quarter of 2003, we converted a $50.0 million treasury lock into a 10-year LIBOR-based swap that becomes effective in March 2004, as discussed below, contemporaneously with the expiration of an existing $50.0 million LIBOR-based swap. The instruments outstanding at June 30, 2003, consist of three separate interest rate swaps with an aggregate notional

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principal amount of $100.0 million outstanding at any one time. The interest rate swaps are based on LIBOR rates and provide for a LIBOR rate of 5.1% for a $50.0 million notional principal amount expiring October 2006, a LIBOR rate of 4.3% for a $50.0 million notional principal amount expiring March 2004 and a LIBOR rate of 5.8% for a $50.0 million notional principal amount that commences in March 2004 and expires in March 2014. All of these instruments are placed with what we believe are large creditworthy financial institutions. Interest on the underlying debt is based on LIBOR plus a margin.

These instruments qualify for hedge accounting as cash flow hedges in accordance with SFAS 133. The effective portion of changes in fair values of these hedges is recorded in OCI until the related hedged item impacts earnings. At June 30, 2003 and 2002, there were losses of $13.4 million and $3.9 million, respectively, deferred in OCI related to our interest rate risk activities. For the six months ended June 30, 2003 and 2002, there were no amounts recognized into earnings related to hedge ineffectiveness.

At June 30, 2003, our weighted average interest rate, excluding non-use and facilities fees, was approximately 5.7%. This rate is based on our June 30, 2003 debt balances and floating rate indices, our credit spread under our credit facilities and the combination of our fixed rate debt and current interest rate hedges. We have locked-in interest rates (excluding the credit spread under the credit facilities) for approximately 57% of our total long-term debt through October 2006, and 47% for the period from October 2006 through September 2012.

Currency Exchange Rate Risk Hedging

Because a significant portion of our Canadian business is conducted in Canadian dollars (CAD), we use certain financial instruments to minimize the risks of unfavorable changes in exchange rates. These instruments include forward exchange contracts, forward extra option contracts and cross currency swaps. Additionally, at June 30, 2003, $8.0 million of our long-term debt was denominated in Canadian dollars ($10.8 million CAD based on a Canadian-U.S. dollar exchange rate of 1.35).

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

The forward exchange contracts and forward extra option contracts qualify for hedge accounting as cash flow hedges, in accordance with SFAS 133. Such derivative activity resulted in a loss of $0.4 million deferred in OCI at June 30, 2003 and a nominal amount at June 30, 2002. For the six months ended June 30, 2003 and 2002, there were no amounts recognized into earnings related to hedge ineffectiveness. The cross currency swaps qualify for hedge accounting as fair value hedges, also in accordance with SFAS 133. Therefore, the change in the fair value of these instruments is recognized currently in earnings. The earnings impact related to our cross currency swaps was a loss of $0.2 million for the six months ended June 30, 2003 and a nominal amount for the six months ended June 30, 2002.

Note 7—Commitments and Contingencies

Litigation

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

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Indemnities

In November, 2002, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We are party to various contracts entered into in the ordinary course of business that contain indemnity provisions pursuant to which we indemnify the counterparties against various expenses. Our indemnity obligations are contingent upon the occurrence of events or circumstances specified in the contracts. No such events or circumstances have occurred at this time, and we do not consider our liability under such indemnity provisions, individually or in the aggregate, to be material to our financial position or results of operations.

Environmental

In connection with our 1999 acquisition of Scurlock Permian LLC from MAP, we were indemnified by MAP for any environmental liabilities attributable to Scurlock’s business or properties which occurred prior to the date of the closing of the acquisition. This indemnity applied to claims that exceeded $25,000 individually and $1.0 million in the aggregate. For the indemnity to apply, we were required to assert any claims on or before May 15, 2003. In conjunction with the expiration of this indemnity, we reached agreement with respect to MAP’s remaining indemnity obligations. Under the terms of this agreement, MAP will continue to remain obligated for liabilities associated with two Superfund sites at which it is alleged that Scurlock Permian deposited waste oils. In addition, MAP paid us $4.6 million cash as satisfaction of its obligations with respect to other sites. Our total environmental reserve, including the reserve associated with the assets that are subject to this agreement, approximated $6.0 million at June 30, 2003. We believe this environmental reserve is adequate. However, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows.

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.

Contingent Equity Issuance

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

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2003, (1.35 Canadian to U.S. dollar exchange rate and $30.84 per unit price) approximately 650,000 units would be issued.

Other

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

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 8—Operating Segments

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

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Note 9—Recent Accounting Pronouncements

In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS 150 establishes standards for classifying and measuring certain financial instruments with characteristics of both liabilities and equity. Financial instruments that fall within the scope of SFAS 150 will be classified as liabilities (or assets in some circumstances). In many cases, these financial instruments were previously classified as equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. We do not have any financial instruments that fall under the scope of this statement and do not believe that the adoption of SFAS 150 will have a material effect on either our financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS No. 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS 133. This Statement is effective for contracts entered into or modified after June 30, 2003 (except for certain exceptions) and for hedging relationships designated after June 30, 2003. We do not believe its adoption will have a material effect on either our financial position, results of operations or cash flows.

In May 2003, the Emerging Issues Task Force (“EITF”) reached consensus on certain issues in EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease.” The consensus provides guidance as to whether an arrangement contains a lease within the scope of SFAS No. 13, “Accounting For Leases.” EITF 01-08

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is effective for arrangements entered into, modified, or acquired in a business combination after June 30, 2003. We do not believe its adoption will have a material impact on either our financial position, results of operations or cash flows.

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

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

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

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