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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on October 14, 2004

Registration No. 333-            



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


FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933


PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact Name of Registrant as Specified in Its Charter)


Delaware
(State or Other Jurisdiction of
Incorporation or Organization)

 

4610
(Primary Standard Industrial
Classification Code Number)

 

76-0582150
(I.R.S. Employer
Identification Number)



333 Clay Street, Suite 1600
Houston, Texas 77002
(713) 646-4100

(Address, Including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)

Tim Moore
Vice President and General Counsel
333 Clay Street, Suite 1600
Houston, Texas 77002
(713) 646-4100
(Name, Address, Including Zip Code, and Telephone Number,
Including Area Code, of Agent for Service)

Copies to:
David P. Oelman
Vinson & Elkins L.L.P.
1001 Fannin Street, Suite 2300
Houston, Texas 77002
(713) 758-2222


Approximate date of commencement of proposed sale to the public: From time to time after this Registration Statement becomes effective.


        If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    ý

        If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

        If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

        If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

        If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.    o


CALCULATION OF REGISTRATION FEE


Title Of Each Class Of
Securities To Be Registered

  Amount to be
Registered(1)

  Proposed Maximum
Offering Price Per Unit(2)

  Proposed Maximum
Aggregate
Offering Price(1)(2)

  Amount of
Registration Fee


Common Units representing limited partner interests(1)   3,245,700 units   $36.40   $118,143,480(2)   $14,969(2)

(1)
Includes the resale of 3,245,700 common units issuable upon the conversion of Class C common units into common units.

(2)
Estimated solely for the purpose of determining the registration fee on the basis of the average high and low prices of the common units on the New York Stock Exchange on October 11, 2004.


        The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.




The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, Dated October    , 2004

P R O S P E C T U S

LOGO

3,245,700 Common Units

Plains All American Pipeline, L.P.

Representing Limited Partner Interests


        Up to 3,245,700 of our common units may be offered from time to time by the selling unitholders named in this prospectus. The selling unitholders may sell the common units at various times and in various types of transactions, including sales in the open market, sales in negotiated transactions and sales by a combination of methods. We will not receive any proceeds from the sale of common units by the selling unitholders.

        Our common units are listed on the New York Stock Exchange under the symbol "PAA."


        Limited partnerships are inherently different from corporations. You should carefully consider each of the factors described under "Risk Factors" which begins on page 2 of this prospectus before you make an investment in the securities.

        NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.


        In connection with certain sales of securities hereunder, a prospectus supplement may accompany this prospectus.

The date of this prospectus is October     , 2004



TABLE OF CONTENTS

 
ABOUT THIS PROSPECTUS
WHO WE ARE
  General
  Business Strategy
RISK FACTORS
  Risks Related to Our Business
  Risks Inherent in an Investment in Plains All American Pipeline
  Tax Risks to Common Unitholders
USE OF PROCEEDS
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
  Introduction
  Executive Summary
  Acquisitions
  Critical Accounting Policies and Estimates
  Recent Accounting Pronouncements
  Change in Accounting Principle
  Results of Operations
  Outlook
  Liquidity and Capital Resources
  Off-Balance Sheet Arrangements
  Quantitative and Qualitative Disclosures About Market Risks
BUSINESS
  General
  Business Strategy
  Financial Strategy
  Competitive Strengths
  Recent Developments
  Organizational History
  Partnership Structure and Management
  Acquisitions and Dispositions
  Description of Segments and Associated Assets
  Customers
  Competition
  Regulation
  Environmental, Health and Safety Regulation
  Operational Hazards and Insurance
  Title to Properties and Rights-of-Way
  Employees
  Litigation
  Unauthorized Trading Loss
MANAGEMENT
  Partnership Management and Governance
  Directors and Executive Officers
  Executive Compensation
 

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  Employment Contracts and Termination of Employment and Change-in-Control Arrangements
  1998 Long-Term Incentive Plan
  Other Equity Grants
  Compensation of Directors
  Reimbursement of Expenses of Our General Partner and its Affiliates
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDERS' MATTERS
  Beneficial Ownership of Limited Partner Units
  Beneficial Ownership of General Partner Interest
  Equity Compensation Plan Information
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
  Our General Partner
  Transactions with Related Parties
DESCRIPTION OF OUR COMMON UNITS
  Meetings/Voting
  Status as Limited Partner or Assignee
  Limited Liability
  Reports and Records
  Class B Common Units
  Class C Common Units
CASH DISTRIBUTION POLICY
  Distributions of Available Cash
  Operating Surplus and Capital Surplus
  Incentive Distribution Rights
  Effect of Issuance of Additional Units
  Quarterly Distributions of Available Cash
  Distributions From Operating Surplus
  Incentive Distribution Rights
  Distributions from Capital Surplus
  Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
  Distribution of Cash Upon Liquidation
DESCRIPTION OF OUR PARTNERSHIP AGREEMENT
  Purpose
  Power of Attorney
  Reimbursements of Our General Partner
  Issuance of Additional Securities
  Amendments to Our Partnership Agreement
  Withdrawal or Removal of Our General Partner
  Liquidation and Distribution of Proceeds
  Change of Management Provisions
  Limited Call Right
  Indemnification
  Registration Rights
TAX CONSIDERATIONS
  Partnership Status
  Limited Partner Status
  Tax Consequences of Unit Ownership
  Tax Treatment of Operations
  Disposition of Common Units
  Uniformity of Units
 

ii


  Tax-Exempt Organizations and Other Investors
  Administrative Matters
  State, Local and Other Tax Considerations
SELLING UNITHOLDERS
PLAN OF DISTRIBUTION
VALIDITY OF THE COMMON UNITS
EXPERTS
WHERE YOU CAN FIND MORE INFORMATION
FORWARD-LOOKING STATEMENTS
INDEX TO FINANCIAL STATEMENTS


ABOUT THIS PROSPECTUS

        This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or SEC, using a "shelf" registration process. Under this shelf process, the selling unitholders may sell up to 3,245,700 of our common units. In connection with certain sales of securities hereunder, a prospectus supplement may accompany this prospectus. The prospectus supplement may also add, update or change information contained in this prospectus. Therefore, before you invest in our securities, you should read this prospectus and any attached prospectus supplements.

        In this registration statement, the terms "we," "our," "ours," and "us" refer to Plains All American Pipeline, L.P. and its subsidiaries, unless otherwise indicated or the context requires otherwise.

iii



WHO WE ARE

General

        We are a publicly traded Delaware limited 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." We have an extensive network of pipeline transportation, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada. Several members of our existing management team founded this midstream crude oil business in 1992, and we completed our initial public offering in 1998.

        We have operations in the United States and Canada, which can be categorized into two primary business activities: crude oil pipeline transportation operations and gathering, marketing, terminalling and storage operations.


Business Strategy

        Our principal business strategy is to capitalize on the regional crude oil supply and demand imbalances that exist in the United States and Canada by combining the strategic location and distinctive capabilities of our transportation and terminalling assets with our extensive marketing and distribution expertise to generate sustainable earnings and cash flow.

        We intend to execute our business strategy by:

        To a lesser degree, we also engage in a similar business strategy with respect to the wholesale marketing and storage of LPG, which we began as a result of an acquisition in mid-2001.

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RISK FACTORS

        You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in us. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.


Risks Related to Our Business

        The level of our profitability is dependent upon an adequate supply of crude oil from fields located offshore and onshore California. Production from these offshore fields has experienced substantial production declines since 1995.

        A significant portion of our segment profit is derived from pipeline transportation margins associated with the Santa Ynez and Point Arguello fields located offshore California. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. We estimate that a 5,000 barrel per day decline in volumes shipped from these fields would result in a decrease in annual pipeline segment profit of approximately $3.1 million. In addition, any production disruption from these fields due to production problems, transportation problems or other reasons would have a material adverse effect on our business.

        Our trading policies cannot eliminate all price risks. In addition, any non-compliance with our trading policies could result in significant financial losses.

        Generally, it is our policy that as we purchase crude oil we establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation under futures contracts on the NYMEX and over-the-counter. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Our policy is generally not to acquire and hold crude oil, futures contracts or derivative products for the purpose of speculating on price changes. This policy cannot, however, eliminate all price risks. For example, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil. While this activity is monitored independently by our risk management function, it exposes us to price risks within predefined limits and authorizations. In addition, any event that disrupts our anticipated physical supply of crude oil could expose us to risk of loss resulting from price changes. Moreover, we are exposed to some risks that are not hedged, including certain basis risks and price risks on certain of our inventory, such as pipeline linefill, which must be maintained in order to transport crude oil on our pipelines.

        In addition, our trading operations involve the risk of non-compliance with our trading policies. For example, we discovered in November 1999 that our trading policy was violated by one of our former employees, which resulted in aggregate losses of approximately $181.0 million. We have taken steps within our organization to enhance our processes and procedures to detect future unauthorized trading. We cannot assure you, however, that these steps will detect and prevent all violations of our trading policies and procedures, particularly if deception or other intentional misconduct is involved.

        If we do not make acquisitions on economically acceptable terms our future growth may be limited.

        Our ability to grow and to increase distributions to unitholders is substantially dependent on our ability to make acquisitions that result in an increase in adjusted operating surplus per unit. If we are unable to make such accretive acquisitions either because (i) we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (ii) we are unable to raise financing for such acquisitions on economically acceptable terms or (iii) we are outbid by competitors, our future growth and ability to raise distributions will be limited. In particular, competition for midstream assets and businesses has intensified substantially and as a result such assets and businesses

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have become more costly. As a result, we may not be able to complete the number or size of acquisitions that we have targeted internally or to continue to grow as quickly as we have historically.

        Our acquisition strategy requires access to new capital. Tightened credit markets or other factors which increase our cost of capital could impair our ability to grow.

        Our business strategy is substantially dependent on acquiring additional assets or operations that will allow us to increase distributions to unitholders. We continuously consider and enter into discussions regarding potential acquisitions. These transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets and operations. Any material acquisition will require access to capital. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our ability to execute our acquisition strategy. Our ability to maintain our targeted credit profile, including maintaining our credit ratings, could impact our cost of capital as well as our ability to execute our acquisition strategy.

        Our acquisition strategy involves risks that may adversely affect our business.

        Any acquisition involves potential risks, including:

        Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from our acquisitions, realize other anticipated benefits and our ability to make distributions to you.

        The nature of our assets and business could expose us to significant environmental compliance costs and liabilities.

        Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons including crude oil and are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment. Compliance with these laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, and even the issuance of injunctions that may restrict or prohibit our operations. Environmental laws and regulations are subject to change, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material affect on our results of operations or earnings. A discharge of hazardous liquids into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and any claims made by neighboring landowners and other third parties for personal injury and property damage.

        The profitability of our pipeline operations depends on the volume of crude oil shipped by third parties.

        Third party shippers generally do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. For example, we estimate that an

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average 10,000 barrel per day variance in the Basin Pipeline System, equivalent to an approximate 4% volume variance on that pipeline system, would change annualized segment profit by approximately $1.0 million.

        The success of our business strategy to increase and optimize throughput on our pipeline and gathering assets is dependent upon our securing additional supplies of crude oil.

        Our operating results are dependent upon securing additional supplies of crude oil from increased production by oil companies and aggressive lease gathering efforts. The ability of producers to increase production is dependent on the prevailing market price of oil, the exploration and production budgets of the major and independent oil companies, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives and other matters beyond our control. There can be no assurance that production of crude oil will rise to sufficient levels to cause an increase in the throughput on our pipeline and gathering assets.

        Our operations are dependent upon demand for crude oil by refiners in the Midwest and on the Gulf Coast. Any decrease in this demand could adversely affect our business.

        Demand for crude oil is dependent upon the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand. Demand also depends on the ability and willingness of shippers having access to our transportation assets to satisfy their demand by deliveries through those assets, and any decrease in this demand could adversely affect our business.

        We face intense competition in our terminalling and storage activities and gathering and marketing activities.

        Our competitors include other crude oil pipelines, the major integrated oil companies, their marketing affiliates, and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control greater supplies of crude oil. We estimate that a $0.01 per barrel variance in the aggregate average segment profit would have an approximate $2.5 million annual effect on segment profit.

        The profitability of our gathering and marketing activities is generally dependent on the volumes of crude oil we purchase and gather.

        To maintain the volumes of crude oil we purchase, we must continue to contract for new supplies of crude oil to offset volumes lost because of natural declines in crude oil production from depleting wells or volumes lost to competitors. Replacement of lost volumes of crude oil is particularly difficult in an environment where production is low and competition to gather available production is intense. Generally, because producers experience inconveniences in switching crude oil purchasers, such as delays in receipt of proceeds while awaiting the preparation of new division orders, producers typically do not change purchasers on the basis of minor variations in price. Thus, we may experience difficulty acquiring crude oil at the wellhead in areas where there are existing relationships between producers and other gatherers and purchasers of crude oil. We estimate that a 5,000 barrel per day decrease in barrels gathered by us would have an approximate $1.0 million per year negative impact on segment profit. This impact is based on a reasonable margin throughout various market conditions. Actual margins vary based on the location of the crude oil, the strength or weakness of the market and the grade or quality of crude oil.

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        We are exposed to the credit risk of our customers in the ordinary course of our gathering and marketing activities.

        There can be no assurance that we have adequately assessed the credit-worthiness of our existing or future counter-parties or that there will not be an unanticipated deterioration in their credit worthiness, which could have an adverse impact on us.

        In those cases where we provide division order services for crude oil purchased at the wellhead, we may be responsible for distribution of proceeds to all parties. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk, and there can be no assurance that we will not experience losses in dealings with other parties.

        Our pipeline assets are subject to federal, state and provincial regulation.

        Our domestic interstate common carrier pipelines are subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be just and reasonable and non-discriminatory. Our intrastate pipeline transportation activities are subject to various state laws and regulations as well as orders of regulatory bodies.

        Our Canadian pipeline assets are subject to regulation by the National Energy Board and by provincial agencies. With respect to a pipeline over which it has jurisdiction, each of these Canadian agencies has the power to determine the rates we are allowed to charge for transportation on such pipeline. The extent to which regulatory agencies can override existing transportation contracts has not been fully decided.

        Our pipeline systems are dependent upon their interconnections with other crude oil pipelines to reach end markets.

        Reduced throughput on these interconnecting pipelines as a result of testing, line repair, reduced operating pressures or other causes could result in reduced throughput on our pipeline systems that would adversely affect our profitability.

        Fluctuations in demand can negatively affect our operating results.

        Fluctuations in demand for crude oil, such as caused by refinery downtime or shutdown, can have a negative effect on our operating results. Specifically, reduced demand in an area serviced by our transmission systems will negatively affect the throughput on such systems. Although the negative impact may be mitigated or overcome by our ability to capture differentials created by demand fluctuations, this ability is dependent on location and grade of crude oil, and thus is unpredictable.

        The terms of our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.

        As of June 30, 2004, pro forma for the third quarter equity and debt offerings, our total outstanding long-term debt was approximately $797.1 million. Various limitations in our indebtedness may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

        Changes in currency exchange rates and foreign currency restrictions and shortages could adversely affect our operating results.

        Because we conduct operations in Canada, we are exposed to currency fluctuations and exchange rate risks that may adversely affect our results of operations. In addition, legal restrictions or shortages in currencies outside the U.S. may prevent us from converting sufficient local currency to enable us to

5



comply with our currency placement obligations not denominated in local currency or to meet our operating needs and debt service requirements.

        Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would substantially reduce our ability to make distributions to you.

        If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate rate. Treatment of us as a corporation would cause a material reduction in our anticipated cash flow, which would materially and adversely affect our ability to make distributions to you.

        In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of such forms of taxation would reduce our cash flow.

        We will be required to comply with Section 404 of the Sarbanes-Oxley Act for the first time.

        The Sarbanes-Oxley Act of 2002 has imposed many new requirements on public companies regarding corporate governance and financial reporting. Among these is the requirement under Section 404 of the Act, beginning with our 2004 Annual Report, for management to report on our internal control over financial reporting and for our independent public accountants to attest to management's report. During 2003, we commenced actions to enhance our ability to comply with these requirements, including but not limited to the addition of staffing in our internal audit department, documentation of existing controls and implementation of new controls or modification of existing controls as deemed appropriate. We have continued to devote substantial time and resources to the documentation and testing of our controls, and to planning for and implementation of remedial efforts in those instances where remediation is indicated. At this point, we have no indication that management will be unable to favorably report on our internal controls nor that our independent auditors will be unable to attest to management's findings. Both we and our auditors, however, must complete the process (which we have never completed before), so we cannot assure you of the results. It is unclear what impact failure to comply fully with Section 404 or the discovery of a material weakness in our internal control over financial reporting would have on us, but presumably it could result in the reduced ability to obtain financing, the loss of customers, and additional expenditures to meet the requirements.


Risks Inherent in an Investment in Plains All American Pipeline

        Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to you.

        Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates, including officers and directors of the general partner, for all expenses incurred on our behalf. The reimbursement of expenses and the payment of fees could adversely affect our ability to make distributions. The general partner has sole discretion to determine the amount of these expenses. In addition, our general partner and its affiliates may provide us services for which we will be charged reasonable fees as determined by the general partner.

        You may not be able to remove our general partner even if you wish to do so.

        Our general partner manages and operates Plains All American Pipeline. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect the general partner or the directors of the general partner on an annual or other continuing basis. Because the owners of our general partner own more than

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one-third of our outstanding units, these owners have the practical ability to prevent the removal of our general partner.

        In addition, the following provisions of our partnership agreement may discourage a person or group from attempting to remove our general partner or otherwise change our management:

        As a result of these provisions, the price at which the common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

        We may issue additional common units without your approval, which would dilute your existing ownership interests.

        Our general partner may cause us to issue an unlimited number of common units, without your approval. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

        We may also issue at any time an unlimited number of equity securities ranking junior to the common units without the approval of the unitholders.

        Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

        If at any time our general partner and its affiliates own 80% or more of the common units, the general partner will have the right, but not the obligation, which it may assign to any of its affiliates, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price generally equal to the then current market price of the common units. As a result, you may be required to sell your common units at a time when you may not desire to sell them or at a price that is less than the price you would like to receive. You may also incur a tax liability upon a sale of your common units.

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        You may not have limited liability if a court finds that unitholder actions constitute control of our business.

        Under Delaware law, you could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the "control" of our business.

        Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our general partner.

        In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

        Conflicts of interest could arise among our general partner and us or the unitholders.

        These conflicts may include the following:


Tax Risks to Common Unitholders

        You should read "Tax Considerations" for a more complete discussion of the following expected material federal income tax consequences of owning and disposing of common units.

        The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to you.

        The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

        If we were classified as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again to you as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon

8



us as a corporation, the cash available for distribution to you would be substantially reduced. Treatment of us as a corporation would result in a material reduction in the after-tax return to the unitholders, likely causing a substantial reduction in the value of the common units.

        Current law may change so as to cause us to be taxed as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution and the target distribution levels will be decreased to reflect that impact on us.

        A successful IRS contest of the federal income tax positions we take may adversely impact the market for common units.

        We have not requested a ruling from the IRS with respect to any matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this registration statement or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain our counsel's conclusions or the positions we take. A court may not concur with our counsel's conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for common units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne by us and directly or indirectly by the unitholders and the general partner.

        You may be required to pay taxes even if you do not receive any cash distributions.

        You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

        Tax gain or loss on disposition of common units could be different than expected.

        If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you. Should the IRS successfully contest some positions we take, you could recognize more gain on the sale of units than would be the case under those positions, without the benefit of decreased income in prior years. Also, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

        If you are a tax-exempt entity, a regulated investment company or an individual not residing in the United States, you may have adverse tax consequences from owning common units.

        Investment in common units by tax-exempt entities, regulated investment companies or mutual funds and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Very little of our income will be qualifying income to a regulated investment company or mutual fund. Distributions to foreign persons will be reduced by withholding taxes at the highest effective U.S.

9



federal income tax rate for individuals, and foreign persons will be required to file federal income tax returns and pay tax on their share of our taxable income.

        We are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder.

        We are registered with the IRS as a "tax shelter." Our tax shelter registration number is 99061000009. The IRS requires that some types of entities, including some partnerships, register as "tax shelters" in response to the perception that they claim tax benefits that the IRS may believe to be unwarranted. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in the unitholders' tax returns and may lead to audits of unitholders' tax returns and adjustments of items unrelated to us. You will bear the cost of any expense incurred in connection with an examination of your personal tax return.

        Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a "reportable transaction." Unitholders may be required to file this form with the IRS if we participate in a "reportable transaction." A transaction may be a reportable transaction based upon any of several factors. Unitholders are urged to consult with their own tax advisor concerning the application of any of these factors to their investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on "material advisors" that organize, manage or sell interests in registered "tax shelters." As stated above, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including unitholder names and tax identification numbers, and to furnish this information to the IRS upon request. Unitholders are urged to consult with their own tax advisor concerning any possible disclosure obligation with respect to their investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

        We treat a purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

        Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that do not conform with all aspects of the Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to your tax returns. Please read "Tax Considerations—Uniformity of Units" in this prospectus for further discussion of the effect of the depreciation and amortization positions we have adopted.

        You will likely be subject to foreign, state and local taxes in jurisdictions where you do not live as a result of an investment in units.

        In addition to federal income taxes, you will likely be subject to other taxes, including foreign taxes, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property and in which you do not reside. We own property and conduct business in Canada and in most states in the United States. You may be required to file Canadian federal income tax returns and to pay Canadian federal and provincial income taxes and to file state and local income tax returns and pay state and local income taxes in many or all of the jurisdictions in which we do business or own property. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all federal, state, local and foreign tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in the common units.

10



USE OF PROCEEDS

        We will not receive any proceeds from the sale of common units by the selling unitholders.

11



PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

        As of September 30, 2004, there were 62,740,218 common units outstanding, held by approximately 340 holders of record, including common units held in street name. The common units are traded on the New York Stock Exchange under the symbol "PAA." An additional 1,307,190 Class B common units and 3,245,700 Class C common units were outstanding as of such date. The Class B common units are held by an affiliate of Plains Holdings Inc. and the Class C common units are held by six holders of record. The Class B common units and the Class C common units are pari passu with and have economic terms substantially similar to the common units but are not publicly traded. Holders of the Class B common units and the Class C common units have the right to demand a meeting of limited partners to vote on whether the Class B common units and Class C common units may be converted at the option of the holders into an equal number of common units. We anticipate that notice of the exercise of such right will be given on October 15, 2004.

        The following table sets forth, for the periods indicated, the high and low sales prices for the common units, as reported on the New York Stock Exchange Composite Transactions Tape, and quarterly cash distributions declared per common unit. The last reported sale price of common units on the New York Stock Exchange on October 11, 2004 was $36.41 per common unit.

 
  Price Range
   
 
  Cash Distributions
per Unit(1)

 
  High
  Low
2002                  
First Quarter   $ 26.79   $ 23.60   $ 0.5250
Second Quarter     27.30     24.60     0.5375
Third Quarter     26.38     19.54     0.5375
Fourth Quarter     24.44     22.04     0.5375

2003

 

 

 

 

 

 

 

 

 
First Quarter   $ 26.90   $ 24.20   $ 0.5500
Second Quarter     31.48     24.65     0.5500
Third Quarter     32.49     29.10     0.5500
Fourth Quarter     32.82     29.76     0.5625

2004

 

 

 

 

 

 

 

 

 
First Quarter   $ 35.23   $ 31.18   $ 0.5625
Second Quarter     36.13     27.25     0.5775
Third Quarter     35.98     31.63     (2)
Fourth Quarter (through October 11, 2004)     36.99     35.76     (2)

(1)
Represents cash distributions attributable to the quarter and paid within 45 days after the quarter.

(2)
The distributions attributable to the third and fourth quarters of 2004 have not yet been declared or paid.

12



SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

        We have derived the historical financial information and operating data below from our audited consolidated financial statements as of and for the years ended December 31, 2003, 2002, 2001, 2000 and 1999 and from our unaudited financial statements as of and for the six months ended June 30, 2004 and 2003. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this prospectus.

 
  Six Months Ended
June 30,

  Year Ended December 31,
 
 
  2004
  2003
  2003
  2002
  2001
  2000
  1999
 
 
  (in millions except per unit data)

 
Statement of operations data:                                            
Revenues   $ 8,936.4   $ 5,991.1   $ 12,589.8   $ 8,384.2   $ 6,868.2   $ 6,641.2   $ 10,910.4  
Cost of sales and field operations (excluding LTIP charge)     8,782.2     5,878.2     12,366.6     8,209.9     6,720.9     6,506.5     10,800.1  
Unauthorized trading losses and related expenses                         7.0     166.4  
Inventory valuation adjustment                     5.0          
LTIP charge—operations(1)     0.5         5.7                  
General and administrative expenses (excluding LTIP charge)     35.1     25.2     50.0     45.7     46.6     40.8     23.2  
LTIP charge—general and administrative(1)     3.7         23.1                  
Depreciation and amortization     29.1     22.2     46.8     34.0     24.3     24.5     17.3  
Restructuring expense                             1.4  
   
 
 
 
 
 
 
 
Total costs and expenses     8,850.6     5,925.6     12,492.3     8,289.6     6,796.8     6,578.8     11,008.4  
Gain on sale of assets                 0.6         1.0     48.2     16.4  
Operating income     85.7     65.4     98.2     94.6     72.4     110.6     (81.6 )
Interest expense     (19.5 )   (17.7 )   (35.2 )   (29.1 )   (29.1 )   (28.7 )   (21.1 )
Interest income and other, net(2)     0.5         (3.6 )   (0.2 )   0.4     (4.4 )   (0.6 )
   
 
 
 
 
 
 
 
Income (loss) from continuing operations before cumulative effect of change in accounting principle(12)   $ 66.7   $ 47.7   $ 59.4   $ 65.3   $ 43.7   $ 77.5   $ (103.4 )
   
 
 
 
 
 
 
 
Basic net income (loss) per limited partner unit before cumulative effect of change in accounting principle(2)(12)   $ 1.03   $ 0.87   $ 1.01   $ 1.34   $ 1.12   $ 2.13   $ (3.21 )
Diluted net income (loss) per limited partner unit before cumulative effect of change in accounting principle(2)(12)   $ 1.03   $ 0.87   $ 1.00   $ 1.34   $ 1.12   $ 2.13   $ (3.21 )
Basic weighted average number of limited partner units outstanding     60.0     51.2     52.7     45.5     37.5     34.4     31.6  
Diluted weighted average number of limited partner units outstanding     60.0     51.2     53.4     45.5     37.5     34.4     31.6  

Balance sheet data (at end of period):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Total assets     2,682.0     1,710.4     2,095.6     1,666.6     1,261.2     885.8     1,223.0  
Total long-term debt(3)(4)     934.8     526.5     519.0     509.7     354.7     320.0     424.1  
Total debt(4)     956.8     544.5     646.2     609.0     456.2     321.3     482.8  
Partners' capital     865.6     600.8     746.7     511.6     402.8     214.0     193.0  

Other data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Maintenance capital expenditures   $ 3.1   $ 4.2   $ 7.6   $ 6.0   $ 3.4   $ 1.8   $ 1.7  
Net cash provided by (used in) operating activities(5)     147.1     204.8     115.3     185.0     (16.2 )   (33.5 )   (71.2 )
Net cash provided by (used in) investing activities(5)     (474.6 )   (139.8 )   (272.1 )   (374.9 )   (263.2 )   211.0     (186.1 )
Net cash provided by (used in) financing activities     334.0     63.0     157.2     189.5     279.5     (227.8 )   305.6  
Declared distributions per limited partner unit(6)(7)(8)     1.13     1.09     2.19     2.11     1.95     1.83     1.59  

Table continued on following page.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13



Operating Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Volumes (thousands of barrels per day)(9)                                            
Pipeline segment:                                            
  Tariff activities                                            
    All American     57     61     59     65     69     74     103  
    Link acquisition     185     N/A     N/A     N/A     N/A     N/A     N/A  
    Capline     112     N/A     N/A     N/A     N/A     N/A     N/A  
    Basin     273     245     263     93     N/A     N/A     N/A  
    Other domestic(10)     408     26     299     219     144     130     61  
    Canada     250     181     203     187     132     N/A     N/A  
  Pipeline margin activities     73     81     78     73     61     60     54  
   
 
 
 
 
 
 
 
    Total     1,358     829     902     637     406     264     218  
   
 
 
 
 
 
 
 

Gathering, marketing, terminalling and storage segment:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Lease gathering     550     430     437     410     348     262     265  
  Bulk purchases(11)     135     78     90     68     46     28     138  
   
 
 
 
 
 
 
 
    Total     685     508     527     478     394     290     403  
   
 
 
 
 
 
 
 
  LPG sales     40     35     38     35     19     N/A     N/A  
   
 
 
 
 
 
 
 

(1)
Compensation expense related to our Long Term Incentive Plan ("LTIP"), see "Management—1998 Long-Term Incentive Plan—Restricted Unit Plan."

(2)
The 2000 and 1999 periods include $15.1 million and $1.5 million, respectively related to losses on the early extinguishment of debt previously classified as an extraordinary item. Effective with the issuance of Statement of Financial Accounting Standards ("SFAS") 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" in April 2002, such items should now be shown as impacting income from continuing operations. As a result of this reclassification, basic and diluted net income (loss) per limited partner unit before cumulative effect of change in accounting principle for 2000 and 1999 were reduced by $0.44 and $0.05, respectively. In addition, effective with the issuance of the Emerging Issues Task Force issued Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128," the 2000 amount was further reduced by $0.07.

(3)
Includes current maturities of long-term debt of $9.0 million, $3.0 million, and $50.7 million at December 31, 2002, 2001 and 1999, respectively, classified as long-term because of our ability and intent to refinance these amounts under our long-term revolving credit facilities.

(4)
The 1999 amount includes a $114.0 million note payable to our former general partner.

(5)
In conjunction with the change in accounting principle we adopted January 1, 2004, we have classified cash flows associated with purchases and sales of linefill on assets that we own as cash flows from investing activities instead of the historical classification as cash flows from operating activities.

(6)
Distributions represent those declared and paid in the applicable period.

(7)
No distributions were declared or paid on subordinated units in the first quarter of 2000. A distribution of $0.45 per unit was declared and paid to holders of common units in that period.

(8)
Our general partner is entitled to receive 2% proportional distributions and also incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. See Note 7 "Partners' Capital and Distributions" in the "Notes to the Consolidated Financial Statements."

(9)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

(10)
We have decreased the number of barrels previously disclosed in the "Other domestic" line for the 2002 period by approximately 9,000. The adjustment reflects an elimination of the duplication caused by reflecting volumes that were transported by truck in addition to being transported by pipeline. We believe this elimination more accurately reflects our business on this pipeline.

(11)
We have decreased the number of barrels previously disclosed in the "Bulk purchases" line for the 2002 period by approximately 12,000. The adjustment reflects an elimination of crude oil volumes improperly classified as bulk purchases.

(12)
Income from continuing operations before cumulative effect of change in accounting principle pro forma for the impact of changing our method of accounting for pipeline linefill in third party assets would have been $61.4 million, $64.8 million, $38.4 million and $78.2 million for each of the four years ended December 31, 2003, respectively. In addition, basic net income per limited partner unit before cumulative effect of change in accounting principle would have been $1.05 ($1.04 diluted), $1.33 ($1.33 diluted), $0.97 ($0.97 diluted) and $2.15 ($2.15 diluted) for each of the four years ended December 31, 2003, respectively. The change had no impact on 1999.

14



MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Introduction

        The following discussion is intended to provide investors with an understanding of our financial condition and results of our operations and should be read in conjunction with our historical consolidated financial statements and accompanying notes included elsewhere in this prospectus.

        Our discussion and analysis includes the following:


Executive Summary

        Company Overview. Plains All American Pipeline, L.P. is a Delaware limited 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. 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 of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada.

        We are one of the largest midstream crude oil companies in North America. As of June 30, 2004, we owned approximately 15,000 miles of crude oil pipelines, approximately 37 million barrels of terminalling and storage capacity and a full complement of truck transportation and injection assets. Currently, we handle an average of over 2.6 million barrels per day of physical crude oil through our extensive network of assets located in major oil producing regions of the United States and Canada. Our operations consist of two operating segments: (i) pipeline operations and (ii) gathering, marketing, terminalling and storage operations ("GMT&S"). Through our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our GMT&S segment, we engage in purchases and resales of crude oil and LPG at various points along the distribution chain and we operate certain terminalling and storage assets.

        Six Months Ended June 30, 2004. During the first six months of 2004, we recognized net income and earnings per limited partner unit of $63.5 million and $0.98, respectively, which was a 33% and 13% increase, respectively, over the first six months of 2003. The results for the first six months of 2004 compared to the first six months of 2003 include significant contributions from the acquisitions completed during the second half of 2003 and the first half of 2004. In addition, the 2004 results

15


include a non-cash gain of approximately $0.5 million resulting from the mark-to-market of open derivative instruments pursuant to Statement of Financial Accounting Standard No. 133, as amended ("SFAS 133"), while the first six months of 2003 includes a non-cash gain of approximately $1.1 million.

        Significant events in the first six months of 2004 that affected our results of operations included the following:

        Fiscal Year 2003. During 2003:

16


        Prospects for the Future. We believe we are well situated to optimize our position in and around our existing assets and to expand our asset base by continuing to consolidate, rationalize and optimize the North American crude oil infrastructure. We have deliberately configured our assets to provide a counter-cyclical balance between our gathering and marketing activities and our terminalling and storage activities. We believe the combination of these balanced activities with our relatively stable, fee-based pipeline assets enables us to generate stable financial results in an industry that is highly cyclical.

        During fiscal year 2004, we have further strengthened our position by expanding our asset base through acquisition and internal growth projects. We will continue to pursue the purchase of assets, and we will also continue to initiate projects designed to optimize crude oil flows in the areas in which we operate. Although we believe that we are well situated in the North American crude oil infrastructure, we face various operational, regulatory and financial challenges that may impact our ability to execute our strategy as planned. See "Risk Factors" and "Forward-Looking Statements" for further discussion of these items.


Acquisitions

        We completed a number of acquisitions that have impacted the results of operations and liquidity discussed herein. The following acquisitions were accounted for, and the purchase price was allocated, in accordance with the purchase method of accounting. We adopted SFAS No. 141, "Business Combinations" in 2001 and followed the provisions of that statement for all business combinations initiated after June 30, 2001. Our ongoing acquisition activity is discussed further in "—Liquidity and Capital Resources" below.

        During the first six months of 2004, we have completed several acquisitions for aggregate consideration of approximately $506.1 million. The aggregate consideration includes cash paid, estimated transaction costs and assumed liabilities and net working capital items. The following table

17


summarizes acquisitions (in millions) for the first six months of 2004, and a description of each of these follows the table:

Acquisition

  Effective
Date

  Acquisition
Price

  Operating
Segment

Capline and Capwood Pipeline Systems   03/01/04   $ 158.5   Pipeline
Link Energy LLC   04/01/04     326.1   Pipeline/GMT&S
Cal Ven Pipeline System   05/01/04     19.0   Pipeline
Other(1)   06/01/04     2.5   Pipeline
       
   
  Total 2004 Acquisitions through June 30, 2004       $ 506.1    
       
   

(1)
Includes several acquisitions that had an immaterial impact on results of operations for the period.

        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 633-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.

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

Crude oil pipelines and facilities   $ 151.4
Crude oil storage and terminal facilities     5.7
Land     1.3
Office equipment and other     0.1
   
  Total   $ 158.5
   

        Link Energy LLC.    On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link for approximately $326 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to PAA from an indemnity escrow account) and approximately $58 million of net liabilities assumed and acquisition related costs. 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 results of operations and assets from this acquisition (the "Link acquisition") have been included in our consolidated financial statements and both our pipeline operations and GMT&S operations segments since April 1, 2004.

18



        The purchase price was allocated as follows and includes goodwill primarily related to Link's gathering and marketing business (in millions):

Fair value of assets acquired:        
Property and equipment   $ 256.3  
Inventory     1.1  
Linefill     48.4  
Inventory in third party assets     15.1  
Goodwill     5.0  
Other long term assets     0.2  
   
 
  Subtotal     326.1  

Accounts receivable

 

 

405.4

 
Other current assets     1.8  
   
 
  Subtotal     407.2  
   
Total assets acquired

 

 

733.3

 

Fair value of liabilities assumed:

 

 

 

 
Accounts payable and accrued liabilities     (448.9 )
Other current liabilities     (8.5 )
Other long-term liabilities     (7.4 )
   
 
  Total liabilities assumed     464.8  

Cash paid for acquisition(1)

 

$

268.5

 
   
 

(1)
Cash paid is net of $5.5 million subsequently returned to us from an indemnity escrow account and does not include the subsequent payment of various transaction and other acquisition related costs.

        We are in the process of evaluating certain estimates made in the purchase price allocation; thus, the allocation is subject to refinement. In addition, we anticipate making capital expenditures of approximately $20.0 million ($9.0 million of which will be spent in 2004) to upgrade certain of the assets and comply with certain regulatory requirements.

        On April 2, 2004, the Office of the Attorney General of Texas (the "Texas AG") 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 Texas AG 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 are coordinating their activities. In connection with the April notice and again in June 2004, the Texas AG requested information from us. We have complied with these requests and are cooperating fully with the antitrust enforcement authorities.

        Cal Ven Pipeline System.    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

19



System includes 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. 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. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our pipeline operations segment since May 1, 2004.

        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. See "—Liquidity and Capital Resources." 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):

Acquisition

  Effective Date
  Acquisition Price
  Operating Segment
Red River Pipeline System   02/01/03   $ 19.4   Pipeline
Iatan Gathering System   03/01/03     24.3   Pipeline
Mesa Pipeline Facility(1)   05/05/03     2.9   Pipeline
South Louisiana Assets(2)   06/01/03     13.4   Pipeline/GMT&S
Alto Storage Facility   06/01/03     8.5   GMT&S
Iraan to Midland Pipeline System   06/30/03     17.6   Pipeline
ArkLaTex Pipeline System   10/01/03     21.3   Pipeline/GMT&S
South Saskatchewan Pipeline System   11/01/03     47.7   Pipeline
Atchafalaya Pipeline System(3)   12/01/03     4.4   Pipeline
       
   
  Total 2003 Acquisitions       $ 159.5    
       
   

(1)
Consists of an 8.8% undivided interest.

(2)
Includes a 33.3% interest in Atchafalaya Pipeline L.L.C. as well as other assets.

(3)
Includes two acquisitions each for 33.3% interests in Atchafalaya Pipeline L.L.C., that when combined with the acquisition referenced in (2) above, results in a total ownership of 100%.

        Shell West Texas Assets.    On August 1, 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 9.0 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the "Shell acquisition") for approximately $324 million. The primary assets included in the transaction are interests in the Basin Pipeline System, the Permian Basin Gathering System and the Rancho Pipeline System. The entire purchase price was allocated to property and equipment.

        The acquired assets are primarily fee-based mainline crude oil pipeline transportation assets that gather crude oil in the Permian Basin and transport the crude oil to major market locations in the Mid-Continent and Gulf Coast regions. The Permian Basin has long been one of the most stable crude

20



oil producing regions in the United States, dating back to the 1930s. The acquired assets complement our existing asset infrastructure in West Texas and represent a transportation link to Cushing, Oklahoma, where we provide storage and terminalling services. In addition, we believe that the Basin Pipeline System is poised to benefit from potential shut-downs of refineries and other pipelines due to the shifting market dynamics in the West Texas area. The Rancho Pipeline System was taken out of service in March 2003, pursuant to the operating agreement. See "Business—Acquisitions and Dispositions—Shutdown and Partial Sale of Rancho Pipeline System."

        Other 2002 Acquisitions.    During February and March of 2002, we completed two other acquisitions for aggregate consideration totaling $15.9 million, with effective dates of February 1, 2002 and March 31, 2002, respectively. These acquisitions include an equity interest in a crude oil pipeline company and crude oil gathering and marketing assets.

        CANPET Energy Group.    In July 2001, we acquired the assets of CANPET Energy Group Inc., a Calgary-based Canadian crude oil and LPG marketing company (the "CANPET acquisition"), for approximately $24.6 million plus excess inventory at the closing date of approximately $25.0 million. A portion of the purchase price, payable in common units or cash, at our option, was deferred subject to various performance standards being met. On April 30, 2004, we satisfied the deferred payment with the issuance of approximately 385,000 common units (representing approximately $13.1 million in value as of the date of issuance) and the payment of $6.5 million in cash. In addition, an incremental $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.

        At the time of the acquisition, CANPET's activities consisted of gathering approximately 75,000 barrels per day of crude oil and marketing an average of approximately 26,000 barrels per day of natural gas liquids or LPGs. The principal assets acquired include a crude oil handling facility, a 130,000-barrel tank facility, LPG facilities, existing business relationships and operating inventory. The acquired assets are part of our strategy to establish a Canadian operation that complements our operations in the United States. The purchase price, as adjusted for post-closing adjustments of $1.0 million, was allocated as follows (in millions):

Inventory   $ 28.1
Goodwill     35.4
Intangible assets (contracts)     1.0
Pipeline linefill     4.3
Crude oil gathering, terminalling and other assets     5.1
   
  Total   $ 73.9
   

        Murphy Oil Company Ltd. Midstream Operations.    In May 2001, we completed the acquisition of substantially all of the Canadian crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. for approximately $158.4 million in cash after post-closing adjustments, including financing and transaction costs (the "Murphy acquisition"). Initial financing for the acquisition was provided through borrowings under our credit facilities. The purchase price included $6.5 million for excess inventory in the pipeline systems. The principal assets acquired include approximately 560 miles of crude oil and condensate mainlines (including dual lines on which condensate is shipped for blending purposes and blended crude is shipped in the opposite direction) and associated gathering and lateral lines, approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 254,000 barrels of pipeline linefill and tank inventories, and 121 trailers used primarily for crude oil transportation. The

21



acquired assets are part of our strategy to establish a Canadian operation that complements our operations in the United States.

        Murphy agreed to continue to transport production from fields previously delivering crude oil to these pipeline systems, under a long-term contract. At the time of acquisition, these volumes averaged approximately 11,000 barrels per day. Total volumes transported on the pipeline system in 2001 were approximately 223,000 barrels per day of light, medium and heavy crudes, as well as condensate.

        The purchase price, as adjusted post-closing, was allocated as follows (in millions):

Crude oil pipeline, gathering and terminal assets   $ 148.0
Pipeline linefill     7.6
Networking capital items     2.0
Other property and equipment     0.5
Other assets, including debt issue costs     0.3
   
  Total   $ 158.4
   

        Other 2001 Acquisitions.    In December 2001, we consummated the acquisition of the Wapella Pipeline System from private investors for approximately $12.0 million, including transaction costs. The entire purchase price was allocated to property and equipment. The system further expands our market in Canada.


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.

        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. These estimates are generally associated with a portion of the last month of each reporting period. We currently estimate that less than 2% of total annual revenues and cost of sales are recorded using estimates and less than 8% of total quarterly revenues and cost of sales are recorded using estimates. Accordingly, a variance from this estimate of 10% would impact the respective line items by less than 1% on both an annual and quarterly basis. Although the resolution of these uncertainties has not historically had a material impact on our reported results of operations or financial condition, because of the high volume, low margin nature of our business, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts. Variances from estimates are reflected in the period actual results become known, typically in the month following the estimate.

22


        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. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

        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 and contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. A variance of 10% in our aggregate estimate would have an approximate $3.0 million impact on earnings. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

        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

23


cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, we cannot provide assurance that actual amounts will not vary significantly from estimated amounts.

Recent Accounting Pronouncements

        In March 2004, the Emerging Issues Task Force issued Issue No. 03-06 ("EITF 03-06"), "Participating Securities and the Two-Class Method under FASB Statement No. 128." EITF 03-06 addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. The adoption of EITF 03-06 may have an impact on earnings per limited partner unit in future periods if net income exceeds distributions or if other participating securities are issued. The effect of applying EITF 03-06 on prior periods was not material except for the year ended December 31, 2000, which has been restated as shown below.

        Basic and Diluted Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle per Limited Partner Unit:

 
  2000
Prior to the adoption of SFAS 145(1) or EITF 03-06   $ 2.64
After the adoption of SFAS 145 but prior to the adoption of EITF 03-06   $ 2.20
After the adoption of both SFAS 145 and EITF 03-06   $ 2.13

(1)
SFAS 145 "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections."


Change in Accounting Principle

        During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third party assets. Historically, we have viewed pipeline linefill, whether in our assets or third party assets, as having long-term characteristics rather than characteristics typically associated with the short-term classification of operating inventory. Therefore, previously we have not included linefill barrels in the same average cost calculation as our operating inventory, but instead have carried linefill at historical cost. Following this change in accounting principle, the linefill in third party assets that we have historically classified as a portion of "Pipeline Linefill" on the face of the balance sheet (a long-term asset) and carried at historical cost, will be included in "Inventory" (a current asset) in determining the average cost of operating inventory and applying the lower of cost or market analysis. At the end of each period, we will reclassify the linefill in third party assets not expected to be liquidated within the succeeding twelve months out of "Inventory" (a current asset), at average cost, and into "Inventory in Third Party Assets" (a long-term asset), which is now reflected as a separate line item within other assets on the consolidated balance sheet.

        This change in accounting principle is effective January 1, 2004 and is reflected in the consolidated statement of operations for the six months ended June 30, 2004 and the consolidated balance sheet as of June 30, 2004. The cumulative effect of this change in accounting principle as of January 1, 2004, is a charge of approximately $3.1 million, representing a reduction in Inventory of approximately $1.7 million, a reduction in Pipeline Linefill of approximately $30.3 million and an increase in Inventory

24



in Third Party Assets of $28.9 million. The pro forma impact for the second quarter of 2003 was not material to net income or net income per basic and diluted limited partner unit. The pro forma impact for the first half of 2003 would have been an increase to net income of approximately $1.8 million ($0.04 per basic and diluted limited partner unit) resulting in pro forma net income of $49.6 million and pro forma net income per limited partner unit (basic and diluted) of $0.91.

        In conjunction with this change in accounting principle, we will classify cash flows associated with purchases and sales of linefill on assets that we own as cash flows from investing activities instead of the historical classification as cash flows from operating activities. Accordingly, the statement of cash flows for the six months ended June 30, 2003 has been revised to reclassify the cash paid for linefill in assets owned from operating activities to investing activities. The effect of the reclassification was an increase to net cash provided by operating activities and net cash used in investing activities of $28.5 million for the six months ended June 30, 2003. As a result of this change in classification, net cash provided by operating activities for the years ended December 31, 2003 and 2002 would increase to $115.3 million from $68.5 million and to $185.0 million from $173.9 million, respectively. Net cash used in investing activities for the years ended December 31, 2003 and 2002 would increase to $272.1 million from $225.3 million and $374.8 million from $363.8 million, respectively. In addition, net cash used in operating activities for the year ended December 31, 2001 would decrease from $30 million to $16.2 million and net cash used in investing activities would increase to $263.2 million from $249.5 million. This change in classification had no impact on the years ended 2000 and 1999.


Results of Operations

        Our operations consist of two operating segments: (1) our Pipeline Operations, through which we engage in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; and (2) our GMT&S 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 segment profit and maintenance capital. We define segment profit as revenues less (i) purchases, (ii) field operating costs and (iii) segment general and administrative ("G&A") expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our "available cash" (as defined in our partnership agreement) to our unitholders. Therefore, we look at each period's earnings before non-cash depreciation and amortization as an important measure of segment performance. The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not account in current periods for the implied reduction in value of our capital assets, such as crude oil pipelines and facilities, caused by aging and wear and tear. Management compensates for this limitation by recognizing that depreciation and amortization are largely offset by repair and maintenance costs, which keep the actual value of our principal fixed assets from declining. These maintenance costs are a component of field operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. 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.

25



        As of June 30, 2004 and December 31, 2003, we owned approximately 15,000 miles and 7,000 miles, respectively, 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 (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 generated by our tariff and other fee-related activities depends on the volumes transported on the pipeline and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. Segment profit from our pipeline capacity leases, barrel exchanges and buy/sell arrangements generally reflect a negotiated amount.

        Our revenues from gathering and marketing activities 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 the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and the sale, revenues and costs related to purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. For example, our revenues from gathering and marketing activities increased approximately 51% in the first half of 2004 compared to the first half of 2003, while our segment profit decreased approximately 3% in the same period. Approximately 55% of the increase in revenues related to increased sales volumes and the remaining 45% of the increase resulted from higher average prices in the 2004 period. The increase in sales volume primarily related to increased lease gathered barrels resulting primarily from the Link acquisition.

        Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in lease gathered volumes and LPG sales volumes. However, although the Link acquisition increased lease gathered barrels and revenues, there was not a corresponding contribution to segment profit as the lease gathered barrels primarily support the pipeline operations. Although we believe that the combination of our lease gathering business and our storage assets provides a counter-cyclical balance, which provides stability in our margins, these margins are not fixed and may vary from period to period. In order to evaluate the performance of this segment, management focuses on the following metrics: (i) segment profit (ii) crude oil lease gathered volumes and LPG sales volumes and (iii) segment profit per barrel calculated on these volumes.

        As of June 30, 2004 and December 31, 2003, we owned approximately 37 million and 24 million, respectively, 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 12.6 million barrels of our 37.0 million barrels of tankage is used primarily in our GMT&S Operations and the balance is used in our Pipeline Operations segment. On a stand-alone basis, segment profit 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

26



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 (when 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 results of operations and cash flows.

        During the first half of 2004, market conditions were generally favorable as the market was in relatively strong backwardation and experienced periods of volatility. The NYMEX benchmark price of crude ranged from $42.38 to $32.20 during the period. The market conditions in the first half of 2003 were more favorable as there was relatively high volatility and strong backwardation throughout the period. Additionally, cold weather during the first quarter of 2003 resulted in increased sales and higher margins in our LPG activities. During the first half of 2003, the NYMEX benchmark price of crude oil ranged from $39.99 to $25.04.

        For the six months ended June 30, 2004, we reported consolidated net income of $63.6 million on total revenues of $8.9 billion compared to net income for the same period in 2003 of $47.7 million on total revenues of $6.0 billion. The following table reflects our results of operations and maintenance

27


capital for each segment (note that each of the items in the following table excludes depreciation and amortization):

 
  Pipeline
  GMT&S
 
 
  (in millions)

 
Six Months Ended June 30, 2004(1)              
Revenues   $ 412.1   $ 8,572.6  
Purchases     (269.6 )   (8,464.2 )
Field operating costs (excluding LTIP charge)     (51.2 )   (45.7 )
LTIP charge—operations     (0.1 )   (0.4 )
Segment G&A expenses (excluding LTIP charge)(2)     (16.3 )   (18.7 )
LTIP charge—general and administrative     (1.7 )   (2.0 )
   
 
 
Segment profit   $ 73.2   $ 41.6  
   
 
 
Noncash SFAS 133 impact(3)   $   $ 0.5  
   
 
 
Maintenance capital   $ 2.1   $ 1.0  
   
 
 

Six Months Ended June 30, 2003(1)

 

 

 

 

 

 

 
Revenues   $ 324.8   $ 5,689.3  
Purchases     (243.6 )   (5,591.9 )
Field operating costs     (27.7 )   (38.0 )
Segment G&A expenses(2)     (9.1 )   (16.1 )
   
 
 
Segment profit   $ 44.4   $ 43.3  
   
 
 
Noncash SFAS 133 impact(3)   $   $ 1.1  
   
 
 
Maintenance capital   $ 3.8   $ 0.4  
   
 
 

(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)
Amounts related to SFAS 133 are included in revenues and impact segment profit.

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

 
  Six Months Ended
June 30,

 
 
  2004
  2003
 
Operating Results (in millions)(1)              
  Revenues              
    Tariff activities   $ 130.9   $ 72.1  
    Pipeline margin activities     281.2     252.7  
   
 
 
  Total pipeline operations revenues     412.1     324.8  
 
Costs and Expenses

 

 

 

 

 

 

 
    Pipeline margin activities purchases     (269.6 )   (243.6 )
    Field operating costs (excluding LTIP charge)     (51.2 )   (27.7 )
    LTIP charge—operations     (0.1 )    
    Segment G&A expenses (excluding LTIP charge)(2)     (16.3 )   (9.1 )
    LTIP charge—general and administrative     (1.7 )    
   
 
 
  Segment profit   $ 73.2   $ 44.4  
   
 
 
  Maintenance capital   $ 2.1   $ 3.8  
   
 
 

Average Daily Volumes (thousands of barrels per day)(3)

 

 

 

 

 

 

 
  Tariff activities              
    All American     57     61  
    Basin     273     245  
    Link acquisition     185     N/A  
    Capline     112     N/A  
    Other domestic     408     261  
    Canada     250     181  
   
 
 
Total tariff activities     1,285     748  

Pipeline margin activities

 

 

73

 

 

81

 
   
 
 
      Total     1,358     829  
   
 
 

(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 total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

        Total average daily volumes transported were approximately 1.4 million barrels per day and 0.8 million barrels per day for the six months ended June 30, 2004 and 2003, respectively. The increase relates to our tariff activities. As discussed above, we have completed a number of acquisitions during

29


2004 and 2003 that have impacted our results of operations. The following table reflects our total average daily volumes from our tariff activities by year of acquisition for comparison purposes:

 
  Six Months Ended June 30,
 
  2004
  2003
 
  (thousands of barrels per day)

Tariff activities(1)        
  2004 acquisitions   396  
  2003 acquisitions   166   33
  All other pipeline systems   723   715
   
 
  Total tariff activities average daily volumes   1,285   748
   
 

(1)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

        Average daily volumes from our tariff activities increased 0.5 million barrels per day to approximately 1.3 million barrels per day. Almost all 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 were relatively unchanged.

        Total revenues from our pipeline operations were approximately $412.1 million and $324.8 million for the six months ended June 30, 2004 and 2003, respectively. An increase in revenues from tariff activities accounted for $58.8 million of the increase. Additionally, our margin activities increased by approximately $28.5 million in the first half of 2004. This increase was related to higher average prices for crude oil sold and transported on our SJV gathering system in the 2004 period as compared to the 2003 period, partially offset by lower buy/sell volumes. Because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. 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 in 2003 because of maintenance being performed on a refinery during that time period.

        Revenues from our tariff activities increased approximately 82% or $58.8 million. The following table reflects our revenues from our tariff activities by year of acquisition for comparison purposes:

 
  Six Months Ended
June 30,

 
  2004
  2003
 
  (in millions)

Tariff activities revenues(1)            
  2004 acquisitions   $ 41.9   $
  2003 acquisitions     17.3     4.0
  All other pipeline systems     71.7     68.1
   
 
  Total tariff activities average daily volumes   $ 130.9   $ 72.1
   
 

(1)
Revenues include intersegment amounts.

        The increase in the first half of 2004 is predominately related to the inclusion of $26.6 million of revenues from the pipelines acquired in the Link acquisition and $15.3 of revenues from other businesses acquired in 2004. Revenues from pipeline systems acquired in 2003 have increased to $17.3 million from $4.0 million. The increase is primarily the result of the inclusion in the first half of

30



2004 of several pipeline systems that were acquired after or during the first half of 2003. See "—Acquisitions." Revenues from all other pipeline systems increased approximately $3.6 million to $71.7 million. The increase is primarily related to increased volumes on our Basin pipeline system and a $1.4 million favorable impact resulting from the decrease in the Canadian dollar to U.S. dollar exchange rate to an average of 1.34 to 1 for the first half of 2004, from an average of 1.45 to 1 for the first half of 2003.

        Field operating costs increased to $51.3 million in the first half of 2004 from $27.7 million in the first half of 2003. This increase is predominately related to our continued growth, primarily from acquisitions, and is comprised primarily of higher payroll and utility costs.

        Segment G&A expenses increased approximately $8.9 million between comparable periods, primarily as a result of our Link acquisition along with a $1.7 million accrual related to the vesting of unit grants under our LTIP. G&A costs have also increased because of increased headcount resulting from continued growth and higher costs related to requirements of the Sarbanes-Oxley Act of 2002. Additionally, the percentage of indirect costs allocated to the pipeline operations segment has increased in the 2004 period as our pipeline operations have grown. Including the impact of the items discussed above, segment profit was approximately $73.2 million for the six months ended June 30, 2004, an increase of 65% as compared to the $44.4 million reported for the six months ended June 30, 2003. Segment profit includes a $0.8 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.

        The following table sets forth our operating results from our GMT&S Operations segment for the comparative periods indicated:

 
  Six Months Ended
June 30,

 
 
  2004
  2003
 
Operating Results (in millions)(1)              
  Revenues   $ 8,572.6   $ 5,689.3  
  Purchases and related costs     (8,464.2 )   (5,591.9 )
  Field operating costs (excluding LTIP charge)     (45.7 )   (38.0 )
  LTIP charge—operations     (0.4 )    
  Segment G&A expenses (excluding LTIP charge)(2)     (18.7 )   (16.1 )
  LTIP charge—general and administrative     (2.0 )    
   
 
 
  Segment profit   $ 41.6   $ 43.3  
   
 
 
  Noncash SFAS 133 impact(3)   $ 0.5   $ 1.1  
   
 
 
  Maintenance capital   $ 1.0   $ 0.4  
   
 
 

Average Daily Volumes (thousands of barrels per day)(4)

 

 

 

 

 

 

 
Crude oil lease gathering     550     430  
Crude oil bulk purchases     135     78  
   
 
 
  Total     685     508  
   
 
 
LPG sales(5)     40     35  
   
 
 

(1)
Revenues and purchases and related costs include intersegment amounts.

Table continued on following page.

31


(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)
Amounts related to SFAS 133 are included in revenues and impact segment profit.

(4)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

(5)
Prior period volumes have been adjusted for consistency of comparison between years. Sales reflect only third party volumes.

        Additionally, field operating costs and segment G&A expenses both increased during the period. Field operating costs increased to approximately $46.1 million in the current period from $38.0 million in the prior year period. This increase is primarily related to the Link acquisition. Also included is an approximately $0.4 million LTIP charge in the 2004 period. Segment G&A expenses increased to $20.7 million in the current period from $16.1 million in the 2003 period. The increase is primarily related to the inclusion of the $2.0 million LTIP charge in the 2004 period and increased headcount from continued growth and higher costs related to Sarbanes-Oxley requirements. This segment G&A increase is partially offset by lower costs being allocated to our GMT&S segment as our Pipeline Operations segment continues to grow.

        The crude oil volumes gathered from producers, using our assets or third-party assets, has increased by 28% during the first half of 2004. The increase is related to the Link acquisition and organic growth and other acquisitions, which has offset natural production declines. In addition, we marketed 40,000 barrels per day of LPG during the first six months of 2004 compared to 35,000 barrels per day in the first six months of 2003. Segment profit per barrel calculated based on our lease gathered crude oil and LPG sales volumes was $0.39 per barrel for the six months ended June 30, 2004, compared to $0.52 for the six months ended June 30, 2003. The impact of change in the non-cash SFAS 133 mark-to-market for the first half of 2004 as compared to the first half of 2003 was a decrease in segment profit per barrel of approximately $0.02. Additionally, segment profit per barrel was negatively impacted by lower segment profit per barrel on the lease gathered barrels added in the 2004 quarter from the Link acquisition. Per barrel profits related to the Link acquisition are lower because Link's gathering business primarily supported its pipeline operations.

        Revenues from our gathering, marketing, terminalling and storage operations were approximately $8.6 billion and $5.7 billion for the six months ended June 30, 2004 and 2003, respectively. As discussed above, revenues and costs related to purchases for the 2004 period were impacted by higher average prices and higher volumes as compared to the 2003 period. The average NYMEX price for crude oil was $36.78 per barrel and $31.42 per barrel for the six months ended June 30, 2004 and 2003, respectively.

        Depreciation and Amortization.    Depreciation and amortization expense was $29.1 million for the six months ended June 30, 2004, compared to $22.2 million for the six months ended June 30, 2003. The increase relates primarily to the assets from our 2004 acquisitions and our various 2003 acquisitions being included for the full six months in 2004 versus only a part or none of the six months in 2003. Additionally, several capital projects were completed during mid-to-late 2003 that were not included in the first six months of 2003 depreciation expense. Amortization of debt issue costs was $1.2 million and $2.0 million in the first half of 2004 and 2003, respectively.

        Interest Expense.    During the first half of 2004, our average debt balance was approximately $771 million. This balance consisted of fixed rate senior notes with a face amount totaling $450 million and borrowings under our revolving credit facilities averaging $321 million. During the comparable 2003 period, our average debt balance was approximately $520 million and consisted of fixed rate senior notes with a face amount of $200 million and borrowings under our revolving credit facilities of

32


$320 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 during the period. Our financial growth strategy is to fund our acquisitions using a balance of debt and equity.

        The net result of the changes to our debt structure and our interest rate hedging instruments mentioned above was an increase in the average amount of fixed rate debt outstanding in the first half of 2004 to approximately 58% as compared to approximately 38% in the first half 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 1.2% in 2004 from 1.3% in 2003.

        The net impact of the items discussed above was an increase in interest expense in the first half of 2004 of approximately $1.8 million to a total of $19.5 million. The higher average debt in the 2004 period resulted in additional interest expense of approximately $6.2 million, while at the same time our commitment and other fees decreased by approximately $1.4 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 4.9% for the first half of 2004 compared to 6.1% for the first half of 2003. The lower weighted average rate decreased interest expense by approximately $3.0 million in the first half of 2004 compared to the first half of 2003.

33



        The following table reflects our results of operations and maintenance capital for each segment (note that each of the items in the following table excludes depreciation and amortization).

 
  Pipeline
  GMT&S
 
 
  (in millions)

 
Year Ended December 31, 2003(1)              
Revenues   $ 658.6   $ 11,985.6  
Purchases     (487.1 )   (11,799.8 )
Field operating costs (excluding LTIP charge)     (60.9 )   (73.3 )
LTIP charge—operations     (1.4 )   (4.3 )
Segment G&A expenses (excluding LTIP charge)(2)     (18.3 )   (31.6 )
LTIP charge—general and administrative     (9.6 )   (13.5 )
   
 
 
Segment profit   $ 81.3   $ 63.1  
   
 
 
Noncash SFAS 133 impact(3)         0.4  
   
 
 
Maintenance capital   $ 6.4   $ 1.2  
   
 
 

Year Ended December 31, 2002(1)

 

 

 

 

 

 

 
Revenues   $ 486.2   $ 7,921.8  
Purchases     (362.2 )   (7,765.1 )
Field operating costs     (40.1 )   (66.3 )
Segment G&A expenses(2)     (13.2 )   (31.5 )
   
 
 
Segment profit   $ 70.7   $ 58.9  
   
 
 
Noncash SFAS 133 impact(3)         0.3  
   
 
 
Maintenance capital   $ 3.4   $ 2.6  
   
 
 

Year Ended December 31, 2001(1)

 

 

 

 

 

 

 
Revenues   $ 357.4   $ 6,528.3  
Purchases     (266.7 )   (6,383.6 )
Field operating costs     (19.4 )   (73.7 )
Segment G&A expenses(2)     (12.4 )   (28.5 )
   
 
 
Segment profit   $ 58.9   $ 42.5  
   
 
 
Noncash SFAS 133 impact(3)   $   $ 0.2  
   
 
 
Maintenance capital   $ 0.5   $ 2.9  
   
 
 

(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)
Amounts related to SFAS 133 are included in revenues and impact segment profit.

34


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

 
  Year Ended December 31,
 
 
  2003
  2002
  2001
 
Operating Results (in millions)(1)                    
Revenues                    
  Tariff activities   $ 153.3   $ 103.7   $ 69.4  
  Pipeline margin activities     505.3     382.5     288.0  
   
 
 
 
Total pipeline operations revenues     658.6     486.2     357.4  
Costs and Expenses                    
  Pipeline margin activities purchases     (487.1 )   (362.2 )   (266.7 )
  Field operating costs (excluding LTIP charge)     (60.9 )   (40.1 )   (19.4 )
  LTIP charge—operations     (1.4 )        
  Segment G&A expenses (excluding LTIP charge)(2)     (18.3 )   (13.2 )   (12.4 )
  LTIP charge—general and administrative     (9.6 )        
   
 
 
 
Segment profit   $ 81.3   $ 70.7   $ 58.9  
   
 
 
 
Maintenance capital   $ 6.4   $ 3.4   $ 0.5  
   
 
 
 

Average Daily Volumes (thousands of barrels per day)(3)(4)

 

 

 

 

 

 

 

 

 

 
Tariff activities                    
  All American     59     65     69  
  Basin     263     93     N/A  
  Other domestic     299     219     144  
  Canada     203     187     132  
   
 
 
 
Total tariff activities     824     564     345  
Pipeline margin activities     78     73     61  
   
 
 
 
  Total     902     637     406  
   
 
 
 

(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 total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

(4)
We have decreased the number of barrels previously disclosed in the "Other domestic" line for the 2002 period by approximately 9,000. The adjustment reflects an elimination of the duplication caused by reflecting volumes that were transported by truck in addition to being transported by pipeline. We believe this elimination more accurately reflects our business on this pipeline.

        Total average daily volumes transported were approximately 902,000 barrels per day for the year ended December 31, 2003, compared to 637,000 barrels per day and 406,000 barrels per day for the years ended December 31, 2002 and 2001, respectively. As discussed above, we have completed a number of acquisitions during 2003 and 2002 that have impacted the results of operations.

35



        The following table reflects our total average daily volumes from our tariff activities by year of acquisition for comparison purposes:

 
  Year Ended December 31,
 
  2003
  2002
  2001
 
  (thousands of barrels per day)

Tariff activities(1)            
  2003 acquisitions   82    
  2002 acquisitions   344   171  
  2001 acquisitions   200   193   134
  All other pipeline systems   198   200   211
   
 
 
    Total tariff activities   824   564   345
   
 
 

(1)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

        The increase in average daily volumes from our tariff activities to 824,000 barrels per day in 2003 from 564,000 barrels per day and 345,000 barrels per day in 2002 and 2001, respectively, resulted primarily from our acquisition activities discussed above. The following discussion explains year-to-year variances based on the comparison of volumes in the table above.

        2003 Acquisitions—Approximately 82,000 barrels per day of the increase in 2003 volumes over 2002 volumes is related to systems acquired during 2003.

        2002 Acquisitions—An additional 173,000 barrels per day of the increase in 2003 resulted from the inclusion of assets acquired in 2002 for the entire year in 2003 as compared to only a portion of 2002. The assets acquired in the Shell acquisition accounted for 171,000 barrels per day of this increase as increased barrels per day on the Basin Pipeline System and the Permian Basin Gathering System coupled with the impact of including a full year results in 2003 as compared to only five months in 2002 more than offset the decrease in barrels per day resulting from the shut-down of the Rancho Pipeline System. See "Business—Acquisitions and Dispositions—Shutdown and Sale of Rancho Pipeline System."

        2001 Acquisitions—In addition, volumes on pipeline systems acquired in 2001 increased by approximately 7,000 barrels per day in the 2003 period as Canadian volumes benefited from the completion of capital expansion projects that allowed for additional volumes on certain pipelines. Barrels per day on these systems increased in the 2002 period as compared to the 2001 period primarily due to the inclusion of the Murphy acquisition for a full year in 2002 compared to only a portion of the year in 2001.

        All other pipeline systems—Volumes on all other pipeline systems decreased approximately 2,000 barrels per day primarily because of a 6,000 barrel per day decrease in our All American tariff volumes and various other decreases totaling 4,000 barrels per day on several of our pipeline systems. The decrease in All American tariff volumes is attributable to a decline in California outer continental shelf ("OCS") production. Partially offsetting these decreases was an 8,000 barrel per day increase in our West Texas Gathering System volumes. Our West Texas Gathering System has benefited from the shutdown of the Rancho pipeline and also from temporary refinery problems that have diverted crude oil barrels from other systems. Volumes on all other pipeline systems decreased by approximately 11,000 barrels per day in 2002 as compared to 2001, primarily because of an approximate 4,000 barrel per day decrease in our All American tariff volumes and a 4,000 barrel per day decrease in our West Texas Gathering System volumes.

36



        Revenues.    Total revenues from our pipeline operations were approximately $658.6 million for the year ended December 31, 2003, compared to $486.2 million and $357.4 million for the years ended December 31, 2002 and 2001, respectively. The increase in revenues was primarily related to our pipeline margin activities, which increased by approximately $122.8 million in 2003. This increase was related to higher average crude oil prices coupled with increased volumes on our buy/sell arrangements on our San Joaquin Valley gathering system in 2003. Because the barrels that we buy and sell are generally indexed to the same pricing indices, revenues and purchases will increase and decrease with changes in market prices without significant changes to our margins related to those purchases and sales. The increase in 2002 over 2001 also was primarily related to our pipeline margin activities on our San Joaquin Valley gathering system. Increased volumes and higher average prices on our buy/sell arrangements were the primary drivers of the increase.

        Revenues from our tariff activities increased approximately 48% or $49.6 million in 2003 as compared to 2002. The following table reflects revenues from our tariff activities by year of acquisition for comparison purposes:

 
  Year Ended December 31,
 
  2003
  2002
  2001
 
  (in millions)

Tariff activities(1)                  
  2003 acquisitions   $ 14.8   $   $
  2002 acquisitions     54.2     23.1    
  2001 acquisitions     28.0     21.6     9.9
  All other pipeline systems     56.3     59.0     59.5
   
 
 
    Total tariff activities   $ 153.3   $ 103.7   $ 69.4
   
 
 

(1)
Revenues include intersegment amounts.

        The increase in revenues from our tariff activities to $153.3 million in 2003 from $103.7 million and $69.4 million in 2002 and 2001, respectively, resulted predominantly from our acquisition activities discussed above. The following discussion explains year-to-year variances based on the comparison of revenues in the table above.

        2003 Acquisitions—Approximately $14.8 million of the increase in 2003 revenues over 2002 revenues is related to systems acquired during 2003.

        2002 Acquisitions—An additional $31.1 million of the increase in 2003 revenues from our tariff activities resulted from the inclusion of assets acquired in 2002 for the entire year in 2003 as compared to only a portion of 2002. This increase was entirely related to the assets acquired in the Shell acquisition as increased revenues on the Basin Pipeline System and the Permian Basin Gathering System coupled with the impact of including a full year results in 2003 as compared to only five months in 2002 more than offset the decrease in revenues resulting from the shut-down of the Rancho Pipeline System. See "Business—Acquisitions and Dispositions—Shutdown and Sale of Rancho Pipeline System."

        2001 Acquisitions—In addition, revenues from 2001 acquisitions increased approximately $6.4 million in 2003 as compared to 2002. This increase predominately resulted from increased Canadian revenues of $6.5 million in the 2003 period primarily due to expanded capacity, higher tariffs and a $3.4 million favorable exchange rate impact. The favorable exchange rate impact has resulted from a decrease in the Canadian dollar to U.S. dollar exchange rate to an average rate of 1.40 to 1 for the year ended December 31, 2003, from an average rate of 1.57 to 1 for the year ended December 31, 2002. Revenues from these systems increased to $21.6 million in 2002 from $9.9 million in 2001

37



primarily because of the inclusion of the Murphy acquisition for a full year in 2002 and increases in the tariff of certain pipeline systems acquired in the Murphy acquisition.

        All other pipeline systems—Revenues from all other pipeline systems were relatively flat for all of the comparable periods as the decrease in volumes attributable to OCS production on our All American system (on which we receive the highest per barrel tariffs among our pipeline operations) was offset in each period by other increases, including increases in the tariffs for OCS volumes transported.

        Field Operating Costs.    Field operating costs increased to $62.3 million in 2003 from $40.1 million and $19.4 million in 2002 and 2001, respectively. The 2003 increase in costs includes $1.4 million related to the accrual made for the probable vesting of unit grants under our LTIP and approximately $1.0 million related to a pipeline spill in Mississippi. The remaining increase is predominately related to our continued growth, primarily from acquisitions, coupled with higher utility costs.

        The increase in field operating costs in 2002 as compared to 2001 was primarily related to the acquisition of businesses in 2002 and late 2001 and the inclusion of the results of the Murphy acquisition for all of 2002 compared to only a portion of 2001. Our field operating costs for the 2002 period also includes a $1.2 million noncash charge associated with the establishment of a liability for potential cleanup of environmental conditions associated with our 1999 acquisitions, based on additional information. In many cases, the actual cash expenditure may not occur for ten years or more.

        Segment G&A Expenses.    Segment G&A expenses were approximately $27.9 million in 2003, compared to approximately $13.2 million and $12.4 million in 2002 and 2001, respectively. The increase in 2003 is primarily a result of a $9.6 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 increased in 2003 as our pipeline operations have grown. The increase in segment G&A expenses in 2002 as compared to 2001 was partially due to increased costs from the assets acquired in the Murphy acquisition related to the inclusion of these assets for all of 2002 compared to only a portion of 2001.

        Segment Profit.    Our pipeline operations segment profit increased 15% to approximately $81.3 million for the year ended December 31, 2003. Pipeline segment profit was approximately $58.9 million in 2001. The primary reasons for the increase in segment profit are discussed above. In addition, segment profit includes a $2.0 million favorable impact resulting from the decrease in the average Canadian dollar to U.S. dollar exchange rate for the 2003 period as compared to the 2002 period.

        Maintenance Capital.    For the periods ended December 31, 2003, 2002 and 2001, maintenance capital expenditures were approximately $6.4 million, $3.4 million and $0.5 million, respectively for our pipeline operations segment. The increases between the years are related to our continued growth, primarily through acquisitions.

38



        The following table sets forth our operating results from our GMT&S segment for the periods indicated:

 
  December 31,
 
 
  2003
  2002
  2001
 
Operating Results (in millions)(1)                    
Revenues   $ 11,985.6   $ 7,921.8   $ 6,528.3  
Purchases and related costs     (11,799.8 )   (7,765.1 )   (6,383.6 )
Field operating costs (excluding LTIP charge)     (73.3 )   (66.3 )   (73.7 )
LTIP charge—operations     (4.3 )        
Segment G&A expenses (excluding LTIP charge)(2)     (31.6 )   (31.5 )   (28.5 )
LTIP charge—general and administrative     (13.5 )        
   
 
 
 
Segment profit   $ 63.1   $ 58.9   $ 42.5  
   
 
 
 
Noncash SFAS 133 impact(3)   $ 0.4   $ 0.3   $ 0.2  
   
 
 
 
Maintenance capital   $ 1.2   $ 2.6   $ 2.9  
   
 
 
 

Average Daily Volumes (thousands of barrels per day)(4)

 

 

 

 

 

 

 

 

 

 
Crude oil lease gathering     437     410     348  
Crude oil bulk purchases(5)     90     68     46  
   
 
 
 
  Total     527     478     394  
   
 
 
 
LPG sales     38     35     19  
   
 
 
 

(1)
Revenue 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)
Amounts related to SFAS 133 are included in revenues and impact segment profit.

(4)
Volumes associated with acquisitions represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

(5)
We have decreased the number of barrels previously disclosed in the "Crude oil bulk purchases" line for the 2002 period by approximately 12,000. The adjustment reflects an elimination of crude oil volumes improperly classified as bulk purchases.

        The following factors contributed to our growth in segment profit during 2003 as compared to 2002:

39


        As discussed above, 2002 market conditions were characterized by periods of weak contango and strong backwardation. Although these conditions are generally disadvantageous for our gathering and marketing activities, the 2001 market conditions were even less favorable. These market conditions and increased crude oil lease gathering volumes contributed to the growth in our segment profit in 2002 as compared to 2001. The increased volumes resulted predominantly from the inclusion of the assets acquired in the CANPET acquisition for the entire year in 2002 as compared to only a portion of 2001. The increase in segment profit was also impacted by decreased field operating costs in the 2002 period as compared to the 2001 period as discussed further below.

        Field operating costs included in segment profit increased to approximately $77.6 million in the year ended December 31, 2003 compared to $66.3 million and $73.7 million for the years ended December 31, 2002 and 2001, respectively. The increase in 2003 includes $4.3 million related to the probable vesting of unit grants under our LTIP. The remaining increase was partially related to our continued growth, primarily from acquisitions, coupled with increased regulatory compliance activities and higher fuel costs. The decrease in field operating costs in 2002 as compared to 2001 was primarily related to the inclusion in 2001 of a $5.0 million noncash writedown of operating crude oil inventory and a $2.0 million noncash reserve for doubtful accounts.

        Segment G&A expenses include the costs directly associated with the segments, as well as a portion of corporate overhead costs considered allocable. See "—Other Income and Expenses." Segment G&A expense increased to $45.1 million in 2003 compared to $31.5 million and $28.5 million for 2002 and 2001, respectively. Included in the 2003 amount is $13.5 million related to the accrual for the probable vesting of unit grants under our LTIP. The percentage of indirect costs allocated to the Gathering, Marketing, Terminalling and Storage Operations segment has decreased from period to period as our pipeline operations have grown, partially offsetting the impact of the overall increase in G&A resulting from our continued growth. Segment G&A expenses increased in 2002 from 2001 primarily because of increased costs of $5.6 million from the assets acquired in the CANPET acquisition due to the inclusion of those assets for all of 2002 compared to only a portion of 2001. This increase was offset by decreased segment G&A of $2.6 million from our domestic operations. This decrease was partially related to a reduction in accounting and consulting costs in 2002 from those that had been incurred in 2001. Partially offsetting these items is the approximately $2.4 million favorable impact on segment profit because of the appreciation of the Canadian dollar.

        The crude oil volumes gathered from producers, using our assets or third-party assets, has increased by 7% and 18% during 2003 and 2002, respectively. The increase in 2003 is primarily related to organic growth and acquisitions, which has offset natural production declines. The increase in 2002 resulted primarily from our acquisition activities. In addition, we marketed 38,000 barrels per day of LPG during 2003 compared to 35,000 barrels per day and 19,000 barrels per day in 2002 and 2001, respectively. The increase in 2002 is primarily related to the inclusion of a full year of our LPG operations in the 2002 period compared to only six months during 2001. Segment profit per barrel calculated based on our lease gathered crude oil and LPG barrels was $0.36 per barrel for the year ended December 31, 2003, compared to $0.36 and $0.32 for the years ended December 31, 2002 and 2001, respectively.

        Revenues from our gathering, marketing, terminalling and storage operations were approximately $12.0 billion, $7.9 billion and $6.5 billion for the years ended December 31, 2003, 2002 and 2001, respectively. As discussed above, revenues and costs related to purchases for 2003 were impacted by higher average prices and higher volumes in the 2003 period as compared to the 2002 period. The average NYMEX price for crude oil was $31.08 per barrel and $26.10 per barrel for 2003 and 2002, respectively. The increase in revenues and costs related to purchases in 2002 as compared to 2001 was predominantly related to higher sales volumes, as the average NYMEX price for crude oil in 2002 was only $0.12 higher than the $25.98 average in 2001.

40



        Maintenance capital.    For the periods ended December 31, 2003, 2002 and 2001, maintenance capital expenditures were approximately $1.2 million, $2.6 million and $2.9 million, respectively for our gathering, marketing, terminalling and storage operations segment. The decrease in 2003 as compared to 2002 and 2001 is primarily because of a reduction in costs associated with information systems and the replacement of a portion of our fleet.

        Unallocated G&A Expenses.    Total G&A expenses were $73.0 million, $45.7 million and $46.6 million for the years ended December 31, 2003, 2002 and 2001, respectively. We have included in the above segment discussion the G&A expenses for each of these years that were attributable to our segments either directly or by allocation. During 2002, we were unsuccessful in our pursuit of several sizable acquisition opportunities determined by auction and one negotiated transaction that had advanced nearly to the execution stage when it was abruptly terminated by the seller. As a result, our 2002 results reflect a $1.0 million charge to G&A expenses associated with the third-party costs of these unsuccessful transactions.

        During 2001, we incurred charges of $5.7 million that were not attributable to a segment, related to incentive compensation paid to certain officers and key employees of Plains Resources and its affiliates. In 1998 (in connection with our IPO) and 2000, Plains Resources granted certain officers and key employees of the former general partner the right to earn ownership in a portion of our common units owned by it. These rights provided for vesting over a three-year period, subject to distributions being paid on the common and subordinated units. In connection with the general partner transition in 2001, these rights, as well as grants to directors under our LTIP, vested. This resulted in a charge to our 2001 income of approximately $6.1 million, of which Plains Resources funded approximately 94%. Approximately $5.7 million of the charge was noncash and was not allocated to a segment.

        Depreciation and Amortization.    Depreciation and amortization expense was $46.8 million for the year ended December 31, 2003, compared to $34.1 million and $24.3 million for the years ended December 31, 2002 and 2001, respectively. The increase in 2003 relates primarily to the inclusion of the assets from the Shell acquisition for the entire year as compared to a portion of 2002. Additionally, several acquisitions were completed during the year along with various capital projects. Amortization of debt issue costs was $3.8 million in 2003, and was essentially unchanged from $3.7 million in 2002.

        The increase in 2002 over 2001 consists of approximately $4.1 million related to the inclusion of assets from the Shell acquisition and approximately $3.5 million related to the inclusion of the assets from the Murphy and CANPET acquisitions for all of 2002 compared to only a portion of 2001. The remainder of the increase is related to increased debt issue costs related to the amendment of our credit facilities during 2002 and late 2001, the sale of senior notes in September 2002 and the completion of various capital projects.

        Interest Expense.    Interest expense was $35.2 million for the year ended December 31, 2003, compared to $29.1 million for each of the years ended December 31, 2002 and 2001, respectively. The increase in 2003 compared to 2002 was primarily related to an increase in the average debt balance during the 2003 period to approximately $525.5 million from approximately $444.6 million in the 2002 period, which resulted in additional interest expense of approximately $5.0 million. The higher average debt balance was primarily due to the portion of the Shell acquisition that was not financed with equity. This debt was outstanding for all of 2003 versus only a portion of 2002. Also, increased commitment and other fees coupled with lower capitalized interest resulted in approximately $2.2 million of the increase in the 2003 period. Our weighted average interest rate decreased slightly during 2003 to 6.0% versus 6.2% in 2002, which decreased our interest expense by approximately $1.1 million. Although the change in our weighted average interest rate was nominal, the change was the net result of various factors that included an increase in the amount of fixed rate, long-term debt,

41



long-term interest rate hedges and declining short-term interest rates. In mid-September 2002, we issued $200 million of ten-year bonds bearing a fixed interest rate of 7.75%. In the fourth quarter of 2002 and the first quarter of 2003, we entered into hedging arrangements to lock in interest rates on approximately $50 million of our floating rate debt. In addition, the average three-month LIBOR rate declined from approximately 1.8% during 2002 to approximately 1.2% during 2003. The net impact of these factors, increased commitment fees and changes in average debt balances decreased the average interest rate by 0.2%.

        Interest expense was relatively flat in the 2002 period as compared to 2001 due to the impact of higher debt levels and commitment fees offset by lower average interest rates and the capitalization of interest. The overall increased average debt balance in 2002 is due to the portion of the Shell acquisition in August 2002 which was not financed with the issuance of equity. During the third quarter of 2001, we issued a $200 million senior secured term B loan, the proceeds of which were used to reduce borrowings under our revolver. As such, our commitment fees on our revolver increased as they are based on unused availability. The lower interest rates in 2002 are due to a decrease in LIBOR and prime rates in the current year. In addition, approximately $0.8 million of interest expense was capitalized during 2002, in conjunction with expansion construction on our Cushing terminal compared to approximately $0.2 million in the 2001 period.

        Other.    During the fourth quarter of 2003 we completed the refinancing of our bank credit facilities with new senior unsecured credit facilities totaling $750 million and a $200 million uncommitted facility for the purchase of hedged crude oil. In addition, during the third quarter of 2003 we made a $34 million prepayment on our senior secured term B loan in anticipation of the refinancing. The completion of these transactions resulted in a non-cash charge of approximately $3.3 million associated with the write-off of unamortized debt issue costs.


Outlook

        Ongoing Acquisition Activities.    Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of transportation, gathering, terminalling or storage assets and related businesses. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations. In an effort to prudently and economically leverage our asset base, knowledge base and skill sets, management has also expanded its efforts to encompass businesses that are closely related to, or significantly intertwined with, the crude oil business. 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.

        During the third quarter of 2004, we acquired the Schaefferstown Propane Storage Facility from Koch Hydrocarbon, L.P. The total purchase price was approximately $32 million. In connection with the transaction, we also acquired an additional $14.2 million of inventory. The facility is located approximately 65 miles northwest of Philadelphia near Schaefferstown, Pennsylvania, and has the capacity to store approximately 20.0 million gallons of refrigerated propane. In addition, the facility has nineteen bullet storage tanks with an aggregate capacity of 570,000 gallons. Propane is delivered to the facility via truck or pipeline and is transported out of the facility by truck. The transaction also included approximately 61 acres of land and a truck rack. The preliminary purchase price was allocated to property and equipment.

        Link Energy LLC Acquisition.    The completion and integration of the Link acquisition began impacting our operating results 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 $25.0 million annually. In addition, we believe that we will realize annual cost savings and synergies of approximately $27.0 million to $32.0 million that are expected to be phased in by the first quarter of 2005 as the

42



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. These costs will have a negative impact in the short-term on our baseline projection for the acquisition.

        OCS Production.    In October 2004, Plains Exploration and Production ("PXP") announced that it had successfully completed an initial development well into the Rocky Point field which is accessible from the Point Arguello platforms and that drilling operations are underway on a second development well. Such drilling activities, if successful, are not expected to have a significant impact on pipeline shipments on our All American Pipeline system in 2004 but, could lead to increased volumes in future periods. However, we can give no assurances that our volumes transported would increase as a result of this drilling activity.

        Distribution Increase.    Management intends to recommend to the board of directors an increase in our quarterly distribution for the third quarter of 2004 to $0.60 per unit, or $2.40 per unit on an annualized basis. If approved by the board, the distribution increase would be effective with the distribution to be paid in mid-November 2004. An annualized distribution rate of $2.40 per unit would represent an increase of approximately 4% over its current annualized distribution of $2.31 per unit and a 9% increase over the November 2003 distribution. You should be aware that management's recommendation is subject to the approval of its board of directors, which holds the sole authority to declare quarterly distributions to unitholders.

        Sarbanes-Oxley Act and New SEC Rules.    Several regulatory and legislative initiatives were introduced in 2002 and 2003 in response to developments during 2001 and 2002 regarding accounting issues at large public companies, resulting disruptions in the capital markets and ensuing calls for action to prevent repetition of those events. Implementation of reforms in connection with these initiatives have added and will add to the costs of doing business for all publicly-traded entities, including us as a partnership. These costs will have an adverse impact on future income and cash flow.

        Among the new requirements is the requirement under Section 404 of the Act, beginning with our 2004 Annual Report, for management to report on our internal control over financial reporting and for our independent public accountants to attest to management's report. During 2003, we commenced actions to enhance our ability to comply with these requirements, including but not limited to the addition of staffing in our internal audit department, documentation of existing controls and implementation of new controls or modification of existing controls as deemed appropriate. We have continued to devote substantial time and resources to the documentation and testing of our controls, and to planning for and implementation of remedial efforts in those instances where remediation is indicated. At this point, we have no indication that management will be unable to favorably report on our internal controls nor that our independent auditors will be unable to attest to management's findings. Both we and our auditors, however, must complete the process (which we have never completed before), so we cannot assure you of the results. It is unclear what impact failure to comply fully with Section 404 or the discovery of a material weakness in our internal control over financial reporting would have on us, but presumably it could result in the reduced ability to obtain financing, the loss of customers, and additional expenditures to meet the requirements.

        Longer Term Outlook.    Our longer-term outlook, spanning a period of five or more years, is influenced by many factors affecting the North American crude oil sector. Some of the more significant trends and factors include:

43


        We believe the collective impact of these trends, factors and developments, many of which are beyond our control, will result in an increasingly volatile crude oil market that is subject to more frequent short-term swings in market prices and grade differentials and shifts in market structure. In an environment of reduced inventories and tight supply and demand balances, even relatively minor supply disruptions can cause significant price swings. Conversely, despite a relatively balanced market on a global basis, competition within a given region of the U.S. could cause downward pricing pressure and significantly impact regional crude oil price differentials among crude oil grades and locations. Although we believe our business strategy is designed to manage these trends, factors and potential developments and that we are strategically positioned to benefit from certain of these developments, there can be no assurance that we will not be negatively affected.


Liquidity and Capital Resources

        Cash generated from operations and our credit facilities are our primary sources of liquidity. At June 30, 2004, we had a working capital deficit of approximately $26.2 million, approximately $342.6 million of availability under our committed revolving credit facilities and $168.0 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 was terminated following our August 2004 debt offering described below. In connection with the Link acquisition, on April 15, 2004, we completed the private placement of 3,245,700 units of Class C common units to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital Advisors for $30.81 per unit. Total proceeds from the transaction, after deducting transaction costs and including the general partner's proportionate contribution, were approximately $101 million, and were used to reduce the balance outstanding under our existing revolving credit facilities.

        In the third quarter of 2004, we completed a public offering of 4,968,000 common units for $33.25 per unit. The offering resulted in gross proceeds of approximately $165.2 million from the sale of units and approximately $3.4 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $7.4 million. Net proceeds of $161.1 million were used to permanently reduce outstanding borrowings under the new $200 million, 364-day credit facility discussed above.

        On August 12, 2004, we sold $175 million of 4.75% senior notes due 2009 and $175 million of 5.88% senior notes due 2016. The 4.75% notes were sold at 99.551% and the 5.88% notes were sold at 99.345% of face value. We used the net proceeds, after deducting initial purchaser discounts and offering costs, of approximately $345.3 million to repay amounts outstanding under our credit facilities,

44



including the remaining balance under the $200 million, 364-day facility we used to fund the Link acquisition, and for general partnership purposes. In connection with this repayment, we terminated the facility. Subsequent to the notes offering, we also terminated our $125 million, 364-day facility, which was scheduled to expire in November 2004.

        We have recently increased the capacity of our uncommitted senior secured hedged inventory facility from $200 million to $300 million, primarily as a result of increased crude oil prices and an increase in our crude oil storage capacity as a result of acquisitions.

        We believe that we have sufficient liquid assets, cash flow from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. However, we are subject to business and operational risks that could adversely affect our cash flow. A material decrease in our cash flows would likely produce an adverse effect on our borrowing capacity.

        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 $125 million to $150 million on expansion capital projects during 2004. In addition, we expect to spend approximately $14.1 million on maintenance capital projects during 2004. For the first half of 2004, we have incurred approximately $32.0 million related to expansion capital projects and approximately $3.1 million on maintenance capital projects.

        We will also have additional cash funding requirements related to the Link acquisition. The aggregate estimated purchase price for the Link acquisition is approximately $326.1 million, of which approximately $268.5 million (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) was funded at closing. The approximately $58.0 million balance includes acquisition related costs and net liabilities assumed.

        Cash flows for the six months ended June 30, 2004 and 2003 were as follows:

 
  Six Months Ended
June 30,

 
 
  2004
  2003
 
 
  (in millions)

 
Cash provided by (used in):              
  Operating activities   $ 147.1   $ 204.8  
  Investing activities     (474.6 )   (139.8 )
  Financing activities     334.0     (63.0 )

        Operating Activities.    The primary drivers of our cash flow from operations are (i) the collection of amounts related to the sale of crude oil and LPG and the transportation of crude oil for a fee and (ii) the payment of amounts related to the purchase of crude oil and LPG and other expenses, principally field operating costs, general and administrative expenses and interest expense. The cash settlement from the purchase and sale of crude oil during any particular month typically occurs within thirty days from the end of the month, except in the months that we store inventory because of contango market conditions. The storage of crude oil in periods of a contango market can have a material impact on our cash flows from operating activities for the period we pay for and store the crude oil and the subsequent period that we receive proceeds from the sale of the crude oil. When we

45



store crude oil, we borrow on our credit facilities to pay for the crude oil and the impact on operating cash flow is negative. Conversely, cash flow from operations increases in the period we collect the cash from the sale of the stored crude oil. To a lesser extent, our cash flow from operating activities is also impacted by the level of LPG inventory stored at period end. Cash flow from operations was $147.1 million and $204.8 million for the six months ended June 30, 2004 and 2003, respectively.

        Investing Activities.    Net cash used in investing activities for the six months ended June 30, 2004 and 2003 consisted predominantly of cash paid for acquisitions. Net cash used in the 2004 period was $474.6 million and was primarily comprised of (i) $142.3 million paid for the Capline and Capwood Pipeline Systems acquisition (a deposit had been paid in December 2003), (ii) approximately $280 million paid for the Link acquisition, (iii) approximately $19 million paid for the CalVen acquisition and (iv) $32.2 million paid for additions to property and equipment. Included in cash paid for additions to property and equipment is (i) approximately $6.6 million related to the Cushing Phase IV expansion, (ii) approximately $5.0 million related to the Iatan System expansion, (iii) approximately $3.0 million of maintenance capital, and (iv) approximately $1.2 million related to the Cushing to Caney pipeline project. Net cash used in investing activities in the 2003 period includes approximately $79.6 million paid for acquisitions and approximately $37.5 million for additions to property and equipment. In addition, approximately $28.5 million was paid for linefill on assets that we own.

        Financing Activities.    Cash provided by financing activities in the 2004 period was approximately $334.0 million and was comprised of (i) approximately $100.9 million of proceeds from the issuance of Class C common units, (ii) net short and long-term borrowings under our revolving credit facility of approximately $403.7 million used primarily to fund the purchase price of the Capline and Link acquisitions, (iii) net repayments under our short-term letter of credit and hedged inventory facility of approximately $96.1 million resulting from the collection of receivables related to prior year sales of inventory that was stored because of contango market conditions, and (iv) $72.7 million of distributions paid to common unitholders and the general partner. Cash used in financing activities in the 2003 period consisted of (i) approximately $63.9 million of proceeds from the issuance of common units used to pay down outstanding balances on the revolving credit facility, (ii) $58.8 million of distributions paid to unitholders and the general partner, (iii) a $7.0 million repayment of a maturity under our senior secured term loan, (iv) net long-term borrowings under our revolving credit facilities of $29.1 million, and (v) net short-term debt repayments of $90.2 million primarily from the proceeds of inventory sales.

        Cash flows for the years ended December 31, 2003, 2002 and 2001 were as follows:

 
  Year ended December 31,
 
 
  2003
  2002
  2001
 
 
  (in millions)

 
Cash provided by (used in):                    
  Operating activities   $ 115.3   $ 185.0   $ (16.2 )
  Investing activities     (272.1 )   (374.9 )   (263.2 )
  Financing activities     157.2     189.5     279.5  

        Operating Activities.    Our positive cash flow from operations for 2003 resulted from cash generated by our recurring operations. In addition, cash flow from operating activities was positively impacted by approximately $74 million related to proceeds received in 2003 from the sale of 2002 hedged crude oil inventory and negatively impacted by approximately $100 million related to inventory stored at the end of 2003. The proceeds from the sale of the 2003 stored crude oil were received in the first quarter of 2004. In 2003, we also received approximately $23 million of additional prepayments over the 2002 balance from counter-parties to mitigate our credit risk, and paid approximately $6.2 million to terminate an interest rate hedge in conjunction with a change in our capital structure.

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        Our positive cash flow from operations for 2002 resulted from cash generated by our recurring operations. In addition, we received approximately $93 million of proceeds during 2002 associated with crude oil hedged and stored during 2001. This was partially offset by the payment of approximately $74 million for crude oil purchased and stored during 2002 but for which receipt of the proceeds occurred during 2003. In addition, our 2002 cash flow from operating activities was positively impacted by the collection of approximately $21 million of prepayments from counter-parties to mitigate our credit risks and the collection of approximately $9.1 million of amounts that had been outstanding primarily since 1999 and 2000.

        Our negative cash flow from operations for 2001 resulted from positive cash generated by our recurring operations offset by the payment of approximately $93 million for crude oil hedged and stored during 2001 for which receipt of the proceeds occurred during 2002.

        Investing Activities.    Net cash used in investing activities in 2003, 2002 and 2001 consisted predominantly of cash paid for acquisitions and purchases of linefill. Net cash used in 2003 was $272.1 million and was comprised of (i) an aggregate $152.6 million paid primarily for ten acquisitions completed during 2003, (ii) a $15.8 million deposit paid on the acquisition from Shell Pipeline Company; see "—Acquisitions", (iii) proceeds of approximately $8.5 million from sales of assets, and (iv) $65.4 million paid for additions to property and equipment, including $19.2 million related to the construction of crude oil gathering and transmission lines in West Texas, and (v) crude oil linefill purchases of approximately $47 million, primarily attributable to increased linefill requirements related to 2003 and 2002 acquisitions. Net cash used in 2002 was $374.9 million and was comprised of (i) an aggregate $324.6 million paid for three acquisitions completed during 2002; see "—Acquisitions", and (ii) $40.6 million paid for additions to property and equipment, primarily related to our Cushing expansion and the construction of the Marshall terminal in Canada, and (iii) crude oil linefill purchases of approximately $11 million. Net cash used in 2001 was $263.2 million and was comprised of (i) an aggregate $229.2 million paid for three acquisitions completed during 2001; see "—Acquisitions", and (ii) $21.1 million paid for additions to property and equipment, and (iii) approximately $13.7 million of crude oil linefill attributable to increased linefill requirements.

        Financing Activities.    Cash provided by financing activities in 2003 consisted primarily of $499.7 million of net proceeds from the issuance of common units and senior unsecured notes, used primarily to fund capital projects and acquisitions and pay down outstanding balances on our revolving credit facilities and senior term loans. Net repayments of our short-term and long-term revolving credit facilities and related senior term loans were $215.4 million. In addition, $121.8 million of distributions were paid to our unitholders and general partner. Cash provided by financing activities in 2002 consisted of approximately $344.6 million of net proceeds from the issuance of common units and senior unsecured notes, used primarily to fund capital projects and acquisitions and pay down outstanding balances on the revolving credit facility. Net repayments of our short-term and long-term revolving credit facilities during 2002 were $49.9 million. In addition, $99.8 million of distributions were paid to our unitholders and general partner during the year ended December 31, 2002.

        Cash provided by financing activities in 2001 consisted primarily of net short-term and long-term borrowings of $134.3 million, proceeds from the issuance of common units of $227.5 million, and the payment of $75.9 million in distributions to our unitholders and general partner.

        Industry Credit Markets and Accounts Receivable.    Throughout the latter part of 2001 and all of 2002, there were significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and extreme financial distress at several large, diversified energy companies, the energy industry was especially impacted by these

47


developments. We believe that these developments have created an increased level of direct and indirect counterparty credit and performance risk.

        The majority of our credit extensions relate to our gathering and marketing activities that can generally be described as high volume and low margin activities. During periods of relatively higher prices, our absolute exposure to any given counterparty may be increased. In our credit approval process, we make a determination of the amount, if any, of the line of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, advance cash payments or "parental" guarantees. As of June 30, 2004, we had received approximately $18.3 million of advance cash payments and prepayments from third parties to mitigate credit risk.

        Pipeline and Storage Regulation.    Some of our petroleum pipelines and storage tanks in the United States are subject to regulation by the U.S. Department of Transportation ("DOT") with respect to the design, installation, testing, construction, operation, replacement and management of pipeline and tank facilities. In addition, we must permit access to and copying of records, and must make certain reports available and provide information as required by the Secretary of Transportation. Comparable regulation exists in Canada and in some states in which we conduct intrastate common carrier or private pipeline operations. See "Business—Regulation—Pipeline and Storage Regulation."

        Regulatory compliance costs include those related to pipeline integrity management and the adoption by the DOT of API 653 as the standard for the inspection, repair, alteration and reconstruction of jurisdictional storage tanks. For our estimates of costs associated with these regulations, see "Business—Regulation—Pipeline and Storage Regulation."

        The DOT is currently considering expanding the scope of its pipeline regulation to include certain gathering pipeline systems that are not currently subject to regulation. This expanded scope would likely include the establishment of additional pipeline integrity management programs for these newly regulated pipelines. The DOT is in the initial stages of evaluating this initiative and we do not currently know what, if any, impact this will have on our operating expenses. However, we cannot assure you that future costs related to the potential programs will not be material.

        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 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. In August 2004, we received a request from the BIS for additional information. We are cooperating with the BIS in its inquiry. 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.

        Alfons Sperber v. Plains Resources Inc., et al.    On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unitholders, asserts breach of fiduciary duty and breach of contract claims against us,

48



Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. The complaint seeks to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. This lawsuit has been settled in principle, subject to the preparation and execution of appropriate settlement documentation and court approval.

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

        Other.    A pipeline, terminal or other facility may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain insurance of various types that we consider adequate to cover our operations and properties. The insurance covers our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. The trend appears to be a contraction in the breadth and depth of available coverage, while costs, deductibles and retention levels have increased. Absent a material favorable change in the insurance markets, this trend is expected to continue as we continue to grow and expand. As a result, we anticipate that we will elect to self-insure more of our activities.

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

        We 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.

        During August 2004, we completed the sale of $175 million of 4.750% senior notes due August 2009 and $175 million of 5.875% senior notes due August 2016. The notes were issued by us and a 100% owned finance subsidiary (neither of which have independent assets or operations) at an aggregate discount of $2.2 million, resulting in an effective average interest rate of 5.40%. Interest payments on each series of notes are due February 15 and August 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries that are minor.

        During December 2003, we completed the sale of $250 million of 5.625% senior notes due December 2013. The notes were issued by us and a 100% owned finance subsidiary (neither of which have independent assets or operations) at a discount of $0.7 million, resulting in an effective interest rate of 5.66%. Interest payments are due on June 15 and December 15 of each year. The notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for subsidiaries that are minor.

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        We have senior unsecured bank credit facilities consisting of:


        We also have a secured $300 million hedged inventory facility (recently increased from $200 million). This facility is an uncommitted working capital facility, which will be used to finance the purchase of hedged crude oil inventory for storage when market conditions warrant. Borrowings under the hedged inventory facility will be secured by the inventory purchased under the facility and the associated accounts receivable, and will be repaid with the proceeds from the sale of such inventory. At June 30, 2004, we had approximately $4.4 million outstanding and $27.6 million of letters of credit issued under our hedged crude oil inventory facility resulting in unused uncommitted capacity of approximately $268.0 million under this facility (pro forma for the recent increase to $300 million).

        Our credit facilities, the indentures governing the 4.750% senior notes, 5.625% senior notes, 5.875% senior notes and 7.75% senior notes contain cross default provisions. Our credit facilities prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting our ability to, among other things:

        Our credit facilities treat a change of control as an event of default and also require us to maintain:

For covenant compliance purposes, letters of credit and borrowings to fund hedged inventory and margin requirements are excluded when calculating the debt coverage ratio.

        A default under our credit facilities would permit the lenders to accelerate the maturity of the outstanding debt. As long as we are in compliance with our credit agreements, they do not restrict our ability to make distributions of available cash as defined in "Cash Distribution Policy—Distributions of Available Cash." We are currently in compliance with the covenants contained in our credit facilities and indentures.

        The average life of our long-term debt capitalization at June 30, 2004, was approximately 6 years. At June 30, 2004 we had approximately $13.2 million of short-term working capital borrowings and $90.0 million of long-term borrowings outstanding under our $425 million U.S. revolving credit facility, no amounts outstanding under our $125 million, 364-day revolving credit facility, $25.7 million outstanding under our $30 million Canadian working capital revolving credit facility, $170.0 million outstanding under our $170 million Canadian revolving credit facility that matures in 2009,

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$200.0 million outstanding under our new $200 million, 364-day revolving credit facility, $200 million of senior notes that mature in 2012 and $250 million of senior notes that mature in 2013.

        Contractual Obligations.    In the ordinary course of doing business we enter into various contractual obligations for varying terms and amounts. The following table includes our non-cancelable contractual obligations as of June 30, 2004, and our best estimate of the period in which the obligation will be settled:

 
  2004
  2005
  2006
  2007
  2008
  Thereafter
  Total
 
  (in millions)

Long-term debt   $   $ 200.0   $   $ 115.8   $   $ 620.0   $ 935.8
Operating leases(1)     9.3     15.8     13.8     10.2     3.8     12.4     65.3
Capital expenditure obligations     76.4                         76.4
Other long-term liabilities     1.5     0.5     0.2                 2.2
   
 
 
 
 
 
 
  Total   $ 87.2   $ 216.3   $ 14.0   $ 126.0   $ 3.8   $ 632.4   $ 1,079.7
   
 
 
 
 
 
 

(1)
Operating leases are primarily for office rent and trucks used in our gathering activities.

        In addition to the items in the table above, we have entered into various operational commitments and agreements related to pipeline operations and to the marketing, transportation, terminalling and storage of crude oil and the marketing and storage of LPG. The majority of these contractual commitments are for the purchase of crude oil and LPG that are made under contracts that range in term from a thirty-day evergreen to three years. A substantial portion of the contracts that extend beyond thirty days include cancellation provisions that allow us to cancel the contract with thirty days written notice. From time to time, we also enter into various types of sale and exchange transactions including fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil futures contracts as hedging devices. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil and LPG purchases and sales and future delivery obligations. The volume and prices of these purchase and sale contracts are subject to market volatility and fluctuate with changes in the NYMEX price of crude oil from period to period. During the second quarter 2004, these purchases averaged approximately $1.6 billion per month.

        Letters of Credit.    In connection with our crude oil marketing, we provide certain suppliers and transporters with irrevocable standby letters of credit to secure our obligation for the purchase of crude oil. Our liabilities with respect to these purchase obligations are recorded in accounts payable on our balance sheet in the month the crude oil is purchased. Generally, these letters of credit are issued for up to seventy-day periods and are terminated upon completion of each transaction. At June 30, 2004, we had outstanding letters of credit under our various facilities of approximately $136.1 million.

        Distributions.    We will distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Available cash is generally defined as all cash and cash equivalents on hand at the end of the quarter less reserves established by our general partner for future requirements. On August 13, 2004, we paid a cash distribution of $0.5775 per unit on all outstanding units. The total distribution paid was approximately $41.8 million, with approximately $38.8 million paid to our common unitholders and approximately $3.0 million paid to our general partner for its general partner ($0.8 million) and incentive distribution interests ($2.2 million).

        Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, our general partner is entitled, without duplication, to 15% of amounts we

51



distribute in excess of $0.450 per limited partner unit, 25% of amounts we distribute in excess of $0.495 per limited partner unit and 50% of amounts we distribute in excess of $0.675 per limited partner unit.

        In 2003, we paid $4.4 million in incentive distributions to our general partner. Thus far in 2004 (through August 13, 2004), we have paid $5.6 million in incentive distributions to our general partner. See "Certain Relationships and Related Transactions—Our General Partner."


Off-Balance Sheet Arrangements

        We have no off-balance sheet arrangements as defined by Item 307 of Regulation S-K.

Quantitative and Qualitative Disclosures About Market Risks

        We are exposed to various market risks, including volatility in (i) crude oil and LPG commodity prices, (ii) interest rates and (iii) currency exchange rates. We utilize various derivative instruments to manage such exposure. 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 our hedging activities address our market risks. We have a risk management function that has direct responsibility and authority for our risk policies and our trading controls and procedures and certain aspects of corporate risk management. To hedge the risks discussed above we engage in price risk management activities that we categorize by the risks we are hedging. The following discussion addresses each category of risk.

        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 (see Note 5 to our consolidated financial statements for a discussion of the mitigation of credit risk beginning on page F-45 of this prospectus). Our policy is to purchase only crude oil for which we have a market, and to structure our sales contracts so that crude oil price fluctuations do not materially affect the segment profit we receive. Except for the controlled trading program discussed below, we do not acquire and hold crude oil futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses.

        While we seek to maintain a position that is substantially balanced within our crude oil lease purchase and LPG 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.

        In order to hedge margins involving our physical assets and manage risks associated with our crude oil purchase and sale obligations, we use derivative instruments, including regulated futures and options transactions, as well as over-the-counter instruments. In analyzing our risk management activities, we draw a distinction between enterprise-level risks and trading-related risks. Enterprise-level risks are those that underlie our core businesses and may be managed based on whether there is value in doing so. Conversely, trading-related risks (the risks involved in trading in the hopes of generating an increased return) are not inherent in the core business; rather, those risks arise as a result of engaging in the trading activity. We have a Risk Management Committee that approves all new risk management strategies through a formal process. With the partial exception of the controlled trading program, our

52



approved strategies are intended to mitigate enterprise-level risks that are inherent in our core businesses of gathering and marketing and storage.

        Although the intent of our risk-management strategies is to hedge our margin, not all of our derivatives qualify for hedge accounting. In such instances, changes in the fair values of these derivatives will receive mark-to-market treatment in current earnings, and result in greater potential for earnings volatility than in the past. This accounting treatment is discussed further under Note 2 "Summary of Significant Accounting Policies" beginning on page F-35 of this prospectus.

        All of our open commodity price risk derivatives at June 30, 2004 were categorized as non-trading. The fair value of these instruments and the change in fair value that would be expected from a 10 percent price decrease are shown in the table below (in millions):

 
  Fair Value
  Effect of 10% Price Decrease
 
Crude oil:              
Futures contracts   $ 18.6   $ (1.4 )
Swaps and options contracts   $ (4.6 ) $ 2.5  

LPG:

 

 

 

 

 

 

 
Futures contracts   $   $  
Swaps and options contracts   $ (1.0 ) $ 1.3  

        The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps and option contracts are estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers. These quotes are compared to the contract price of the swap, which approximates the gain or loss that would have been realized if the contracts had been closed out at year end. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used. The assumptions in these estimates as well as the source is maintained by the independent risk control function. All hedge positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent decrease in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.

        We utilize both fixed and variable rate debt, and are exposed to market risk due to the floating interest rates on our credit facilities. Therefore, from time to time we utilize interest rate swaps and collars to hedge interest obligations on specific debt issuances, including anticipated debt issuances. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for variable rate debt outstanding at December 31, 2003. The 7.75% senior notes issued during 2002 and the 5.625% senior notes issued during 2003 are fixed rate notes and their interest rates are not subject to market risk. Our variable rate debt bears interest at LIBOR, prime or the bankers acceptance plus the applicable margin. The average interest rates presented below are based upon rates

53


in effect at June 30, 2004. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates.

 
  Expected Year of Maturity
 
 
  2004
  2005
  2006
  2007
  2008
  Thereafter
  Total
 
 
  (in millions)

 
Liabilities:                                            
  Short-term debt—variable rate   $ 22.0   $   $   $   $   $   $ 22.0  
    Average interest rate     3.3 %                       3.3 %
  Long-term debt—variable rate   $   $ 200.0   $   $ 115.8   $   $ 170.0   $ 485.8  
    Average interest rate         2.3 %       2.8 %       2.3 %   2.4 %

        Our cash flow stream relating to our Canadian operations is based on the U.S. dollar equivalent of such amounts measured in Canadian dollars. Assets and liabilities of our Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.

        Because a significant portion of our Canadian business is conducted in Canadian dollars, we use certain financial instruments to minimize the risks of changes in the exchange rate. 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 December 31, 2003, we did not have any Canadian dollar debt. All of the financial instruments utilized are placed with large creditworthy financial institutions.

        At June 30, 2004, we had forward exchange contracts that allow us to exchange $2.0 million Canadian for at least $1.5 million U.S. quarterly during 2004 (based on a Canadian dollar to U.S. dollar exchange rate of 1.33 to 1) and $1.0 million Canadian for at least $0.7 million U.S. quarterly during 2005 (based on a Canadian dollar to U.S. dollar exchange rate of 1.34 to 1). At June 30, 2004, we also had cross currency swap contracts for an aggregate notional principal amount of $21.0 million effectively converting this amount of our U.S. dollar denominated debt to $32.5 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 2005 and has a final maturity in May 2006 ($19.0 million U.S.).

        We estimate the fair value of these instruments based on current termination values. The table shown below summarizes the fair value of our foreign currency hedges by year of maturity (in millions):

 
  Year of Maturity
 
 
  2004
  2005
  2006
  2007
  Total
 
Forward exchange contracts   $ 0.1   $   $   $   $ 0.1  
Cross currency swaps     (0.2 )   (0.6 )   (2.8 )       (3.6 )
   
 
 
 
 
 

Total

 

$

(0.1

)

$

(0.6

)

$

(2.8

)

$


 

$

(3.5

)
   
 
 
 
 
 

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BUSINESS

General

        We are a publicly traded Delaware limited partnership, formed in 1998 and 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." We have an extensive network of pipeline transportation, storage and gathering assets in key oil producing basins and at major market hubs in the United States and Canada. Our operations can be categorized into two primary business activities:


Business Strategy

        Our principal business strategy is to capitalize on the regional crude oil supply and demand imbalances that exist in the United States and Canada by combining the strategic location and distinctive capabilities of our transportation and terminalling assets with our extensive marketing and distribution expertise to generate sustainable earnings and cash flow.

        We intend to execute our business strategy by:

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        To a lesser degree, we also engage in a similar business strategy with respect to the wholesale marketing and storage of LPG, which we began as a result of an acquisition in mid-2001. Since that time, the portion of our Gathering, Marketing, Terminalling and Storage Operations segment profit associated with those activities has increased from $4.2 million in 2001 to $10.0 million in 2002 and $11.6 million in 2003. The segment profit for 2001 reflects results from July 1 through December 31.


Financial Strategy

        We believe that a major factor in our continued success will be our ability to maintain a competitive cost of capital and access to the capital markets. Since our initial public offering in 1998, we have consistently communicated to the financial community our intention to maintain a strong credit profile that we believe is consistent with an investment grade credit rating. We have targeted a general credit profile with the following attributes:

        Based on our second quarter 2004 results, and pro forma for our third quarter 2004 equity and debt offerings, we were within our targeted credit profile. In order for us to maintain our targeted credit profile and achieve growth through acquisitions, we intend to fund acquisitions using approximately equal proportions of equity and debt. In certain cases, acquisitions will initially be financed using debt since it is difficult to predict the actual timing of accessing the market to raise equity. Accordingly, from time to time we may be temporarily outside the parameters of our targeted credit profile.

        In July 2004, Standard & Poor's removed us from creditwatch with negative implications and affirmed their BBB- stable senior unsecured rating (an investment grade rating). In August 2004, Moody's Investors Service upgraded our senior unsecured rating from Ba1 to Baa3 (an investment grade rating). We cannot assure you that these ratings will remain in effect for any given period of time or that one or both of these ratings will not be lowered or withdrawn entirely by a rating agency. You should note that a credit rating is not a recommendation to buy, sell or hold securities, and may be revised or withdrawn at any time.

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Competitive Strengths

        We believe that the following competitive strengths position us to successfully execute our principal business strategy:

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Recent Developments

        On July 23, 2004, in connection with the acquisition of Plains Resources Inc. by Vulcan Energy Corporation, Plains All American GP LLC (the general partner of our general partner Plains AAP, L.P.), amended its limited liability company agreement to expand its board of directors from seven members to eight. As amended, the limited liability company agreement provides that the mechanism for determining the constituency of the board remains the same except that three independent directors, rather than two, are elected by majority vote of the owners of Plains All American GP LLC. Mr. J. Taft Symonds, the previous designee of Plains Holdings Inc., was elected as an independent director by majority vote of the members of Plains All American GP LLC to fill the vacancy created by the expansion of the board.

        On July 26, 2004, Plains Holdings Inc. (a wholly owned subsidiary of Plains Resources Inc.) designated Mr. David N. Capobianco as one of our directors. Mr. Capobianco is a member of the board of Vulcan Energy Corporation and a managing director of Vulcan Capital, an affiliate of Vulcan Inc.

        On August 13, 2004, we paid a cash distribution of $0.5775 per unit on all outstanding limited partner units. This distribution equals an annual distribution of $2.31 per unit and represents an increase of 5.0% over the second quarter of 2003 distribution. Management intends to recommend to the board of directors an increase in our quarterly distribution to $0.60 per unit, or $2.40 per unit on an annualized basis. If approved by the board, the distribution increase would be effective with the distribution to be paid in mid-November 2004. An annualized distribution rate of $2.40 per unit would represent an increase of approximately 4% over its current annualized distribution of $2.31 per unit and a 9% increase over the November 2003 distribution. You should be aware that management's recommendation is subject to the approval of its board of directors, which holds the sole authority to declare quarterly distributions to unitholders.

        In August 2004, we acquired the Schaefferstown Propane Storage Facility from Koch Hydrocarbon, L.P. The total purchase price was approximately $32 million. In connection with the transaction, we also acquired an additional $14.2 million of inventory. The facility is located approximately 65 miles northwest of Philadelphia near Schaefferstown, Pennsylvania, and has the capacity to store approximately 20.0 million gallons of refrigerated propane. In addition, the facility has nineteen bullet storage tanks with an aggregate capacity of 570,000 gallons. Propane is delivered to the facility via truck or pipeline and is transported out of the facility by truck. The transaction also included approximately 61 acres of land and a truck rack. The preliminary purchase price was allocated to property and equipment.

        During the third quarter of 2004, we completed a public offering of 4,968,000 common units. The net proceeds from the offering, including our general partner's proportionate capital contribution and expenses associated with the offering, were approximately $161.1 million. We used the net proceeds to pay down outstanding indebtedness and reduce the commitment level under our $200 million, 364-day credit facility.

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        From January 1, 2004 through September 30, 2004, we have issued approximately 363,000 common units in satisfaction of the vesting of phantom units under our Long-Term Incentive Plan.

        During August 2004, we completed the sale of $175 million of 4.750% senior notes due August 2009 and $175 million of 5.875% senior notes due August 2016 in a private placement pursuant to Rule 144A of the Securities Act of 1933. The net proceeds from the offering, after deducting the initial purchasers' discounts and our estimated offering expenses, were approximately $345.3 million. We used the net proceeds to repay the remaining balance of approximately $40.8 million outstanding under our $200 million, 364-day credit facility. Following this payment, this facility was terminated and we used the remaining net proceeds to repay amounts outstanding under our revolving credit facilities and for general partnership purposes. As a result of this transaction, we recognized a noncash charge of approximately $0.7 million associated with the write-off of unamortized debt issue costs.

        Since 1998, including our recent Schaefferstown acquisition, we have completed numerous acquisitions for an aggregate purchase price of approximately $1.9 billion. Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of assets and operations that are strategic and complimentary to our existing operations. Such assets and operations include crude oil related assets and LPG assets, as well as energy assets that are closely related to, or intertwined with, these business lines, and enable us to leverage our asset base, knowledge base and skill sets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations.


Organizational History

        We were formed in September 1998 to acquire and operate the midstream crude oil business and assets of Plains Resources Inc. and its wholly-owned subsidiaries as a separate, publicly traded master limited partnership. We completed our initial public offering in November 1998. Unless the context otherwise requires, we refer to Plains Resources Inc. and its wholly owned subsidiaries as Plains Resources. As a result of subsequent equity offerings and the purchase in 2001 by senior management and a group of financial investors of majority control of our general partner and a portion of the limited partner units held by Plains Resources, Plains Resources' overall effective ownership in us was reduced to approximately 18.9% as of September 30, 2004. See "Security Ownership of Certain Beneficial Owners and Management and Related Unitholders' Matters."

        As a result of the 2001 transaction, our 2% general partner interest is held by Plains AAP, L.P., a Delaware limited partnership. Plains All American GP LLC, a Delaware limited liability company, is Plains AAP, L.P.'s general partner. Unless the context otherwise requires, we use the term "general partner" to refer to both Plains AAP, L.P. and Plains All American GP LLC. Plains AAP, L.P. and Plains All American GP LLC are essentially held by seven owners with the largest interest, 44%, held by Plains Resources. We use the phrase "former general partner" to refer to the subsidiary of Plains Resources that formerly held the general partner interest.

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Partnership Structure and Management

        Our operations are conducted through, and our operating assets are owned by, our subsidiaries. We own our interests in our subsidiaries through two operating partnerships, Plains Marketing, L.P. and Plains Pipeline, L.P. Our Canadian operations are conducted through Plains Marketing Canada, L.P.

        Our general partner, Plains AAP, L.P., is a limited partnership. Our general partner is managed by its general partner, Plains All American GP LLC, which has ultimate responsibility for conducting our business and managing our operations. References to our general partner, unless the context otherwise requires, include Plains All American GP LLC. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for all direct and indirect expenses incurred on our behalf.

        The chart on the next page depicts the current structure and ownership of Plains All American Pipeline, L.P. and certain subsidiaries.

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Partnership Structure

GRAPHIC

61


Acquisitions and Dispositions

        An integral component of our business strategy and growth objective is to acquire assets and operations that are strategic and complementary to our existing operations. Such assets and operations include crude oil related assets and LPG assets, as well as energy assets that are closely related to, or intertwined with, these business lines, and enable us to leverage our asset base, knowledge base and skill sets. We have established a target to complete, on average, $200 million to $300 million in acquisitions per year, subject to availability of attractive assets on acceptable terms. Since 1998, we have completed numerous acquisitions for an aggregate purchase price of approximately $1.9 billion. In addition, from time to time we have sold assets that are no longer considered essential to our operations.

        Following is a brief description of selected acquisitions completed during the first half of 2004 and in 2003 and major acquisitions and dispositions that have occurred since our initial public offering in November 1998.

        On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link for approximately $326 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to PAA from an indemnity escrow account) and approximately $58 million of net liabilities assumed and acquisition related costs. 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 results of operations and assets from this acquisition (the "Link acquisition") have been included in our consolidated financial statements and both our pipeline operations and gathering, marketing, terminalling and storage operations segments since April 1, 2004.

        On April 2, 2004, the Office of the Attorney General of Texas (the "Texas AG") 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 Texas AG 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 are coordinating their activities. In connection with the April notice and again in June 2004, the Texas AG requested information from us. We have complied with these requests and are cooperating fully with the antitrust enforcement authorities.

        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 includes 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. The Rainbow

62


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. The results of operations and assets from this acquisition have been included in our consolidated financial statements and our pipeline operations segment since May 1, 2004.

        In March 2004, we completed the acquisition of all of Shell Pipeline Company LP's ("SPLC") 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 Pipe Line System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a 633-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capline system is one of the primary transportation routes for crude oil shipped into the Midwestern U.S., accessing over 2.7 million barrels of refining capacity in PADD II, including refineries owned by ConocoPhillips, ExxonMobil, BP, MarathonAshland, CITGO and Premcor. Capline has direct connections to a significant amount of sweet and light sour crude production in the Gulf of Mexico. In addition, with its two active docks capable of handling 600,000-barrel tankers as well as access to LOOP, the Louisiana Offshore Oil Port, the Capline System is a key transporter of sweet and light sour foreign crude to PADD II. With a total system operating capacity of 1.14 million barrels per day, approximately 248,000 barrels per day are subject to the interest acquired. During 2003, throughput on the interest we acquired averaged approximately 125,000 barrels per day.

        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 Capwood system has an operating capacity of 277,000 barrels per day of crude oil. Of that capacity, approximately 211,000 barrels per day are subject to the interest acquired. The Capwood System has the ability to deliver crude at Wood River to several other PADD II refineries and pipelines, including those owned by Koch and ConocoPhillips. Movements on the Capwood system are driven by the volumes shipped on Capline as well as Canadian crude that can be delivered to Patoka via the Mustang Pipeline. Since closing, we have assumed the operatorship of the Capwood system from SPLC.

        In November 2003, we completed the acquisition of the South Saskatchewan Pipeline System from South Saskatchewan Pipe Line Company. The South Saskatchewan Pipeline System originates approximately 75 miles southwest of Swift Current, Saskatchewan, and traverses north and east until it reaches its terminus at Regina, Saskatchewan. The system consists of a 158-mile, 16-inch mainline and 203 miles of gathering lines ranging in diameter from three to twelve inches. In 2002, the system transported approximately 52,000 barrels of crude oil per day. During the period of 2003 that we owned the system, it transported approximately 52,000 barrels of crude oil per day. For the six months ended June 30, 2004, the system transported approximately 47,000 barrels of crude oil per day. At Regina, the system can deliver crude oil to the Enbridge Pipeline System, as well as to local markets, and through the Enbridge connection crude can be delivered into our Wascana Pipeline System. Total purchase price for these assets was approximately $48 million, including transaction costs.

        In October 2003, we completed the acquisition of the ArkLaTex Pipeline System from Link Energy (formerly EOTT Energy). The ArkLaTex Pipeline System consists of 240 miles of active crude oil gathering and mainline pipelines and connects to our Red River Pipeline System near Sabine, Texas. Also included in the transaction were 470,000 barrels of active crude oil storage capacity, the

63


assignment of certain of Link Energy's crude oil supply contracts and crude oil linefill and working inventory comprising approximately 108,000 barrels. The total purchase price for these assets of approximately $21.3 million included approximately $14.0 million of cash paid to Link Energy for the pipeline system, approximately $2.9 million of cash paid to Link Energy to purchase crude oil linefill and working inventory, approximately $3.6 million for estimated near-term capital costs and transaction costs and approximately $0.8 million associated with the satisfaction of outstanding claims for accounts receivable and inventory balances.

        In June 2003, we acquired the Iraan to Midland Pipeline System from a unit of Marathon Ashland Petroleum LLC ("MAP") for aggregate consideration of approximately $17.6 million. The Iraan to Midland Pipeline System is a 16-inch, 98-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. The Iraan to Midland Pipeline System transported approximately 22,000 barrels per day of crude oil in the first six months of 2004. The results of operations and assets of the Iraan to Midland Pipeline System have been included in our consolidated financial statements and our pipeline operations since June 30, 2003. 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 $0.4 million of estimated transaction costs.

        In June 2003, we completed the acquisition of terminalling and gathering assets from El Paso Corporation for approximately $13.4 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 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. The assets acquired in this acquisition include a 331/3% interest in Atchafalaya Pipeline, L.L.C. In December 2003, we acquired the remaining 662/3% interests in two separate transactions totaling $4.4 million.

        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 360 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.

        In February 2003, we completed the acquisition of a 334-mile crude oil pipeline from BP Pipelines (North America) Inc. for approximately $19.4 million, including transaction costs. The system originates at Sabine in East Texas and terminates near Cushing, Oklahoma. Subsequent to the acquisition, we connected the pipeline system to our Cushing Terminal. The system also includes approximately 645,000 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.

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        On August 1, 2002, we acquired interests in approximately 2,000 miles of gathering and mainline crude oil pipelines and approximately 9.0 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the "Shell acquisition"). The primary assets included in the transaction are interests in the Basin Pipeline System ("Basin System"), the Permian Basin Gathering System ("Permian Basin System") and the Rancho Pipeline System ("Rancho System"). The total purchase price of $324.4 million consisted of (i) $304.0 million in cash, which was borrowed under our revolving credit facility, (ii) approximately $9.1 million related to the settlement of pre-existing accounts receivable and inventory balances and (iii) approximately $11.3 million of estimated transaction and closing costs.

        The acquired assets are primarily fee-based mainline crude oil pipeline transportation assets that gather crude oil in the Permian Basin and transport that crude oil to major market locations in the Mid-Continent and Gulf Coast regions. The acquired assets complement our existing asset infrastructure in West Texas and represent a transportation link to Cushing, Oklahoma, where we provide storage and terminalling services. In addition, we believe that the Basin system is poised to benefit from potential shut-downs of refineries and other pipelines due to the shifting market dynamics in the West Texas area. As was contemplated at the time of the acquisition, the Rancho system was taken out of service in March 2003, pursuant to the terms of its operating agreement. See "—Shutdown and Partial Sale of Rancho Pipeline System."

        In early 2000, we articulated to the financial community our intent to establish a strong Canadian operation that complements our operations in the United States. In 2001, after evaluating the marketplace and analyzing potential opportunities, we consummated the two transactions detailed below in 2001. The combination of these assets, an established fee-based pipeline transportation business and a rapidly-growing, entrepreneurial gathering and marketing business, allowed us to optimize both businesses and establish what we believe to be a solid foundation for future growth in Canada.

        CANPET Energy Group, Inc.    In July 2001, we purchased substantially all of the assets of CANPET Energy Group Inc., a Calgary-based Canadian crude oil and LPG marketing company, for approximately $24.6 million plus $25.0 million for additional inventory owned by CANPET. In December 2003 we recorded an additional $24.3 million related to a portion of the purchase price that had previously been deferred subject to various performance standards of the business acquired. See Note 7 "Partners' Capital and Distributions" in the "Notes to the Consolidated Financial Statements." The principal assets acquired included a crude oil handling facility, a 130,000-barrel tank facility, LPG facilities, existing business relationships and operating inventory.

        Murphy Oil Company Ltd. Midstream Operations.    In May 2001, we completed the acquisition of substantially all of the Canadian crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. for approximately $161.0 million in cash, including financing and transaction costs. The purchase price included $6.5 million for excess inventory in the systems. The principal assets acquired include (i) approximately 560 miles of crude oil and condensate mainlines (including dual lines on which condensate is shipped for blending purposes and blended crude is shipped in the opposite direction) and associated gathering and lateral lines, (ii) approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, (iii) approximately 254,000 barrels of pipeline linefill and tank inventories, and (iv) 121 trailers used primarily for crude oil transportation.

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        In July 1999, we completed the acquisition of the West Texas Gathering System from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. The assets acquired include approximately 420 miles of crude oil mainlines, approximately 295 miles of associated gathering and lateral lines, and approximately 2.7 million barrels of tankage located along the system.

        In May 1999, we completed the acquisition of Scurlock Permian LLC ("Scurlock") and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million. Financing for the acquisition was provided through $117.0 million of borrowings under our revolving credit facility and the sale of 1.3 million Class B common units to our former general partner for total cash consideration of $25.0 million.

        Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum, was engaged in crude oil transportation, gathering and marketing. The assets acquired included approximately 2,300 miles of active pipelines, numerous storage terminals and a fleet of trucks. The largest asset consists of an approximately 954-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets we acquired also included approximately one million barrels of crude oil linefill.

        Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of assets and operations that are strategic and complimentary to our existing operations. Such assets and operations include crude oil related assets and LPG assets, as well as energy assets that are closely related to, or intertwined with, these business lines, and enable us to leverage our asset base, knowledge base and skill sets. Such acquisition efforts involve participation by us in processes that have been made public, involve a number of potential buyers and are commonly referred to as "auction" processes, as well as situations where we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. These acquisition efforts often involve assets which, if acquired, would have a material effect on our financial condition and results of operations.

        In connection with our acquisition activities, we routinely incur third party costs, which are capitalized and deferred pending final outcome of the transaction. Deferred costs associated with successful transactions are capitalized as part of the transaction, while deferred costs associated with unsuccessful transactions are expensed at the time of such final determination. We had a total of approximately $0.2 million in deferred costs at June 30, 2004. 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.

        We acquired an interest in the Rancho Pipeline System in conjunction with the Shell acquisition. The Rancho Pipeline System Agreement dated November 1, 1951, pursuant to which the system was constructed and operated, terminated in March 2003. Upon termination, the agreement required the owners to take the pipeline system, in which we owned an approximate 50% interest, out of service. Accordingly, we notified our shippers and did not accept nominations for movements after February 28, 2003. This shutdown was contemplated at the time of the acquisition and was accounted for under purchase accounting in accordance with SFAS No. 141 "Business Combinations." The pipeline was shut down on March 1, 2003 and a purge of the crude oil linefill was completed in April 2003. In June 2003,

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we completed transactions whereby we transferred all of our ownership interest in approximately 241 miles of the total 458 miles of the pipeline in exchange for $4.0 million and approximately 500,000 barrels of crude oil tankage in West Texas. In August 2004 we sold all of our remaining ownership interest in the system to Kinder Morgan Texas Pipeline, L.P. for approximately $870,000.

        In March 2000, we sold the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas to a unit of El Paso Corporation for $129.0 million. Except for minor third party volumes, one of our subsidiaries, Plains Marketing, L.P., was the sole shipper on this segment of the pipeline since its predecessor acquired the line from the Goodyear Tire & Rubber Company in July 1998. We realized net proceeds of approximately $124.0 million after the associated transaction costs and estimated costs to remove equipment. We used the proceeds from the sale to reduce outstanding debt. We recognized a gain of approximately $20.1 million in connection with the sale.

        We had suspended shipments of crude oil on this segment of the pipeline in November 1999. At that time, we owned approximately 5.2 million barrels of crude oil in the segment of the pipeline. We sold this crude oil from November 1999 to February 2000 for net proceeds of approximately $100.0 million, which were used for working capital purposes. We recognized an aggregate gain of approximately $44.6 million, of which approximately $28.1 million was recognized in 2000 in connection with the sale of the linefill.


Description of Segments and Associated Assets

        Our business activities are conducted through two primary segments, Pipeline Operations and Gathering, Marketing, Terminalling and Storage Operations. Our operations are conducted in approximately 40 states in the United States and six provinces in Canada. The majority of our operations are conducted in Texas, Oklahoma, California, Kansas and Louisiana and in the Canadian provinces of Alberta and Saskatchewan.

        Following is a description of the activities and assets for each of our business segments:

        As of June 30, 2004, we owned approximately 15,000 miles of gathering and mainline crude oil pipelines located throughout the United States and Canada. Our activities from pipeline operations generally consist of transporting crude oil for a fee and third party leases of pipeline capacity, as well as barrel exchanges and buy/sell arrangements.

        Substantially all of our pipeline systems are controlled or monitored from one of two central control rooms with computer systems designed to continuously monitor real-time operational data, including measurement of crude oil quantities injected into and delivered through the pipelines, product flow rates, and pressure and temperature variations. The systems are designed to enhance leak detection capabilities, sound automatic alarms in the event of operational conditions outside of pre-established parameters and provide for remote-controlled shut-down of pump stations on the pipeline systems. Pump stations, storage facilities and meter measurement points along the pipeline systems are linked by telephone, satellite, radio or a combination thereof to provide communications for remote monitoring and in some instances control, which reduces our requirement for full-time site personnel at most of these locations.

        We perform scheduled maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We attempt to control corrosion of the mainlines through the use of cathodic protection, corrosion inhibiting chemicals injected into the crude stream and other

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protection systems typically used in the industry. Maintenance facilities containing equipment for pipe repairs, spare parts and trained response personnel are strategically located along the pipelines and in concentrated operating areas. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and regulations, standards prescribed by the American Petroleum Institute and accepted industry practice. See "—Regulation—Pipeline and Storage Regulation."

        Following is a description of our major pipeline assets in the United States and Canada, grouped by geographic location:

        Basin Pipeline System.    We acquired an approximate 87% undivided joint interest in the Basin System in the Shell acquisition. The Basin System is a 515-mile mainline, telescoping crude oil system with a capacity ranging from approximately 144,000 barrels per day to 394,000 barrels per day depending on the segment. System throughput (as measured by system deliveries) was approximately 273,000 barrels per day (net to our interest) during the first six months of 2004. The Basin System consists of three primary movements of crude oil: (i) barrels are shipped from Jal, New Mexico to the West Texas markets of Wink and Midland, where they are exchanged and/or further shipped to refining centers; (ii) barrels are shipped to the Mid-Continent region on the Midland to Wichita Falls segment and the Wichita Falls to Cushing segment; and (iii) foreign and Gulf of Mexico barrels are delivered into Basin at Wichita Falls and delivered to a connecting carrier or shipped to Cushing for further distribution to Mid-Continent or Midwest refineries. The size of the pipe ranges from 20 to 24 inches in diameter. The Basin system also includes approximately 5.8 million barrels (5.0 million barrels, net to our interest) of crude oil storage capacity located along the system. TEPPCO Partners, L.P. owns the remaining approximately 13% interest in the system. In 2004, we expanded a 424-mile section of the system extending from Midland, Texas to Cushing, Oklahoma. With the completion of this $1.8 million expansion, the capacity of this section has increased approximately 15%, from 350,000 barrels per day to approximately 400,000 barrels per day. The Basin system is subject to tariff rates regulated by the Federal Energy Regulatory Commission (the "FERC"). See "—Regulation—Transportation Regulation."

        West Texas Gathering System.    The West Texas Gathering System is a common carrier crude oil pipeline system located in the heart of the Permian Basin producing area, and includes approximately 420 miles of crude oil mainlines and approximately 295 miles of associated gathering and lateral lines. The West Texas Gathering System has the capability to transport approximately 190,000 barrels per day. Total system volumes were approximately 80,000 barrels per day in the first six months of 2004. Chevron USA has agreed to transport its equity crude oil production from fields connected to the West Texas Gathering System on the system through July 2011 (representing approximately 18,000 barrels per day, or 21% of the total system volumes during 2003). The system also includes approximately 2.7 million barrels of crude oil storage capacity, located primarily in Monahans, Midland, Wink and Crane, Texas.

        Permian Basin Gathering System.    The Permian Basin System, acquired in the Shell acquisition, includes several gathering systems and trunk lines with connecting injection stations and storage facilities. In total, the system consists of 919 miles of pipe and primarily transports crude oil from wells in the Permian Basin to the Basin System. The Permian Basin System gathered approximately 48,000 barrels per day in the first six months of 2004. The Permian Basin System includes approximately 3.9 million barrels of crude oil storage capacity.

        Spraberry Pipeline System.    The Spraberry Pipeline System, acquired in the Scurlock acquisition, gathers crude oil from the Spraberry Trend of West Texas and transports it to Midland, Texas, where it interconnects with the West Texas Gathering System and other pipelines. The Spraberry Pipeline

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System consists of approximately 954 miles of pipe of varying diameter, and has a throughput capacity of approximately 50,000 barrels of crude oil per day. The Spraberry Trend is one of the largest producing areas in West Texas, and we are one of the largest gatherers in the Spraberry Trend. For the first six months of 2004, the Spraberry Pipeline System gathered approximately 38,000 barrels per day of crude oil. The Spraberry Pipeline System also includes approximately 659,000 barrels of tank capacity located along the pipeline, including the recent expansion.

        Dollarhide Pipeline System.    The Dollarhide Pipeline System, acquired from Unocal Pipeline Company in October 2001, is a common carrier pipeline system that is located in West Texas. in the first six months of 2004, the Dollarhide Pipeline System delivered approximately 6,000 barrels of crude oil per day into the West Texas Gathering System. The system also includes approximately 55,000 barrels of crude oil storage capacity along the system.

        Mesa Pipeline System.    The Mesa Pipeline System, in which we acquired an 8.8% undivided interest from Unocal Corporation in May 2003, 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. We 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.

        Iraan to Midland Pipeline System.    The Iraan to Midland Pipeline System, acquired from a unit of Marathon Ashland Petroleum LLC in June 2003, is a 16-inch, 98-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 the first six months of 2004, deliveries averaged approximately 22,000 barrels per day.

        Iatan Gathering System.    The Iatan gathering system, acquired from Navajo Refining Company, L.P. in March 2003, is located in the Permian Basin in West Texas and consists of approximately 360 miles of active crude oil gathering lines. During the first six months of 2004, volumes on this system averaged 22,000 barrels per day.

        New Mexico Pipeline System.    The New Mexico Pipeline System, included in the April 2004 Link transaction, is an extensive crude oil mainline and gathering system primarily located in Lea and Eddy Counties, New Mexico. The system consists of approximately 1,200 miles of active pipe and approximately 1.3 million barrels of associated storage. The system delivers primarily to the Basin Pipeline System, an Amoco Pipeline System, and the Kaston Pipeline system. For the second quarter of 2004, volumes averaged approximately 67,000 barrels per day.

        Texas Pipeline System.    The Texas Pipeline System, included in the April 2004 Link transaction, is an extensive crude oil mainline and gathering system delivering crude oil produced in the Permian Basin primarily to Midland, McCamey, and Colorado City, Texas. Also, included in the system is a 10" mainline from McCamey, Texas to Healdton, Oklahoma and approximately 2.0 million barrels of storage. For the second quarter of 2004, volumes averaged approximately 103,000 barrels per day.

        All American Pipeline System.    The segment of the All American Pipeline that we retained following the sale of the line segment to El Paso is a common carrier crude oil pipeline system that transports crude oil produced from certain outer continental shelf, or OCS, fields offshore California to locations in California. This segment is subject to tariff rates regulated by the FERC.

        We own and operate the segment of the system that extends approximately 10 miles along the California coast from Las Flores to Gaviota (24-inch diameter pipe) and continues from Gaviota approximately 126 miles to our station in Emidio, California (30-inch diameter pipe). Between Gaviota and our Emidio Station, the All American Pipeline interconnects with our San Joaquin Valley, or SJV,

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Gathering System as well as various third party intrastate pipelines, including the Unocap Pipeline System, the Shell Pipeline Company, L.P. and the Pacific Pipeline.

        The All American Pipeline currently transports OCS crude oil received at the onshore facilities of the Santa Ynez field at Las Flores and the onshore facilities of the Point Arguello field located at Gaviota. ExxonMobil, which owns all of the Santa Ynez production, and PXP and other producers, which together own approximately 75% of the Point Arguello production, have entered into transportation agreements committing to transport all of their production from these fields on the All American Pipeline. These agreements, which expire in August 2007, provide for a minimum tariff with annual escalations based on specific composite indices. The producers from the Point Arguello field who do not have contracts with us have no other means of transporting their production and, therefore, ship their volumes on the All American Pipeline at the posted tariffs. Volumes attributable to PXP are purchased and sold to a third party under our marketing agreement with PXP before such volumes enter the All American Pipeline. See "Certain Relationships and Related Transactions—Transactions with Related Parties—General." The third party pays the same tariff as required in the transportation agreements. At December 31, 2003, the tariffs averaged $1.71 per barrel. Effective January 1, 2004, based on the contractual escalator, the average tariff increased to $1.81 per barrel. The agreements do not require these owners to transport a minimum volume.

        A significant portion of our revenues less direct field operating costs is derived from the pipeline transportation business associated with these two fields. The relative contribution to our revenues less direct field operating costs from these fields has decreased from approximately 23% in 1999 to 17% in 2003, as we have grown and diversified through acquisitions and organic expansions and as a result of declines in volumes produced and transported from these fields, offset somewhat by an increase in pipeline tariffs. Over the last several years, transportation volumes received from the Santa Ynez and Point Arguello fields have declined from 92,000 and 60,000 average daily barrels, respectively, in 1995 to 46,000 and 11,000 average daily barrels, respectively, for the first six months of 2004. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. A 5,000 barrel per day decline in volumes shipped from these fields would result in a decrease in annual pipeline tariff revenues of approximately $3.3 million, based on a tariff of $1.81 per barrel.

        In October 2004, PXP announced that it had successfully completed an initial development well into the Rocky Point field which is accessible from the Point Arguello platforms and that drilling operations are underway on a second development well. Such activities are not expected to have a significant impact on pipeline shipments on our All American Pipeline system in 2004. If successful, such incremental drilling activity could lead to increased volumes on our All American Pipeline System in future periods. However, we can give no assurance that our volumes transported would increase as a result of this drilling activity.

        The table below sets forth the historical volumes received from both of these fields for the past five years and the six months ended June 30, 2004:

 
   
  Year Ended December 31,
 
  Six Months
Ended June 30,
2004

 
  2003
  2002
  2001
  2000
  1999
 
  (barrels in thousands)

Average daily volumes received from:                        
  Point Arguello (at Gaviota)   11   13   16   18   18   20
  Santa Ynez (at Las Flores)   46   46   50   51   56   59
   
 
 
 
 
 
    Total   57   59   66   69   74   79
   
 
 
 
 
 

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        SJV Gathering System.    The SJV Gathering System is connected to most of the major fields in the San Joaquin Valley. The SJV Gathering System was constructed in 1987 with a design capacity of approximately 140,000 barrels per day. The system consists of a 16-inch pipeline that originates at the Belridge station and extends 45 miles south to a connection with the All American Pipeline at the Pentland station. The SJV Gathering System also includes approximately 730,000 barrels of tank capacity, which can be used to facilitate movements along the system as well as to support our other activities.

        The table below sets forth the historical volumes received into the SJV Gathering System for the past five years and the six months ended June 30, 2004:

 
   
  Year Ended December 31,
 
  Six Months
Ended June 30,
2004

 
  2003
  2002
  2001
  2000
  1999
 
  (barrels in thousands)

Total average daily volumes   73   78   73   61   60   84

        Butte Pipeline System.    We own an approximate 22% equity interest in Butte Pipe Line Company, which in turn owns the Butte Pipeline System, a 370-mile mainline system that runs from Baker, Montana to Guernsey, Wyoming. The Butte Pipeline System is connected to the Poplar Pipeline System, which in turn is connected to the Wascana Pipeline System, which is located in our Canadian Region and is wholly owned by us. The total system volumes for the Butte Pipeline System during the first six months of 2004 were approximately 66,000 barrels of crude oil per day (approximately 15,000 barrels per day, net to our 22% interest). The operator of the system is Bridger Pipeline.

        North Dakota Systems.    The North Dakota Systems, included in the April 2004 Link acquisition, consist of the Bowman-Baker Pipeline System, the Trenton Pipeline System and the North Dakota Gathering System. Aggregate volumes on the systems averaged approximately 46,000 barrels per day for the second quarter of 2004. The Bowman-Baker System is a 283-mile, FERC regulated common carrier pipeline system from Harding County, South Dakota to the Butte Pipeline System at Baker, Montana. The Trenton Pipeline System consists of 116 miles of active pipeline from Richland County, Montana to Williston County, North Dakota delivering crude to Enbridge's Portal Pipeline System. The North Dakota Gathering System consists of approximately 220 miles of active pipeline located in the Williston Basin region of North Dakota. The system delivers primarily to Tesoro pipeline for consumption at Tesoro's Mandan Refinery or to the Little Missouri Pipeline, a feeder of the Butte Pipeline System.

        Sabine Pass Pipeline System.    The Sabine Pass Pipeline System, acquired in the Scurlock acquisition, is a common carrier crude oil pipeline system. The Sabine Pass Pipeline System primarily gathers crude oil from onshore facilities of offshore production near Johnson's Bayou, Louisiana, and delivers it to tankage and barge loading facilities in Sabine Pass, Texas. The Sabine Pass Pipeline System consists of approximately 51 miles of pipe ranging from 4 to 10 inches in diameter and has a throughput capacity of approximately 26,000 barrels of crude oil per day. During the first six months of 2004, the system transported approximately 15,000 barrels of crude oil per day. The Sabine Pass Pipeline System also includes 245,000 barrels of tank capacity located along the pipeline.

        Ferriday Pipeline System.    The Ferriday Pipeline System, acquired in the Scurlock acquisition, is a common carrier crude oil pipeline system located in eastern Louisiana and western Mississippi. The Ferriday Pipeline System consists of approximately 570 miles of pipe ranging from 2 inches to 12 inches in diameter. During the first six months of 2004, the Ferriday Pipeline System delivered approximately 7,000 barrels of crude oil per day to third party pipelines that supplied refiners in the Midwest. The Ferriday Pipeline System also includes approximately 332,000 barrels of tank capacity located along the pipeline.

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        La Gloria Pipeline System.    The La Gloria Pipeline System, acquired in the Scurlock acquisition, is a proprietary crude oil pipeline system that during the first six months of 2004, transported approximately 22,000 barrels of crude oil per day to Crown Central's refinery in Longview, Texas. Crown Central's deliveries are subject to a throughput and deficiency agreement, which extends through 2004.

        Red River Pipeline System.    The Red River Pipeline System, acquired in 2003, is a 334-mile crude oil pipeline system that originates at Sabine in East Texas, and terminates near Cushing, Oklahoma. The Red River system has a capacity of up to 22,000 barrels of crude oil per day, depending upon the type of crude oil being transported. During the first six months of 2004, the system transported approximately 11,000 barrels of crude oil per day. The system also includes approximately 645,000 barrels of crude oil storage capacity. In 2003, we completed a connection of the pipeline system to our Cushing Terminal.

        ArkLaTex Pipeline System.    The ArkLaTex Pipeline System, acquired from Link Energy (formerly EOTT Energy) in September 2003, consists of 240 miles of active crude oil gathering and mainline pipelines and connects to our Red River Pipeline System near Sabine, Texas. Also included in the transaction were 470,000 barrels of active crude oil storage capacity. During the first six months of 2004, volumes transported averaged 8,000 barrels per day.

        Atchafalaya Pipeline System.    The Atchafalaya Pipeline System, which we own 100% through three separate transactions in 2003, originates near Garden City, Louisiana and traverses east to its terminus near Gibson, Louisiana. The system consists of 35 miles of active 8-inch crude oil and condensate pipelines. During the first six months of 2004, the system transported approximately 15,000 barrels per day of crude oil and condensate.

        Eugene Island Flowline System.    The Eugene Island Flowline System ("EIFS") is a 57-mile offshore gathering pipeline located in the Eugene Island federal lease block area of the Gulf of Mexico. The system delivers crude oil gathered offshore to the Burns Terminal and to the Burns dock barge-loading facility in south Louisiana. The total system volumes for the EIFS during the first half of 2004 were approximately 12,000 barrels per day of crude oil.

        Capline/Capwood Pipeline System.    The Capline Pipeline System, in which we acquired a 22% undivided joint interest from Shell in March 2004, is a crude oil pipeline system that runs from St. James, Louisiana to Patoka, Illinois. The Capline Pipeline System consist of 633 miles of 40-inch pipe. The Capline Pipeline System is one of the primary transportation routes for crude oil shipped into the Midwestern U.S., accessing over 2.7 million barrels of refining capacity in PADD II, including refineries owned by ConocoPhillips, ExxonMobil, BP, MarathonAshland, CITGO and Premcor. Capline has direct connections to a significant amount of sweet and light sour crude production in the Gulf of Mexico. In addition, with its two active docks capable of handling 600,000-barrel tankers as well as access to LOOP, the Louisiana Offshore Oil Port, it is a key transporter of sweet and light sour foreign crude to PADD II. With a total system operating capacity of 1.14 million barrels per day of crude oil, approximately 248,000 barrels per day are subject to the interest acquired by us. Since acquisition, throughput on the interest acquired averaged approximately 168,000 barrels per day. The Capwood Pipeline System, in which we acquired a 76% undivided joint interest from Shell in March 2004, is a crude oil pipeline system that runs from Patoka, Illinois to Wood River, Illinois. The Capwood Pipeline System consists of 57 miles of 20-inch pipe. The Capwood Pipeline System has an operating capacity of 277,000 barrels per day of crude oil. Of that capacity, approximately 211,000 barrels per day are subject to the interest acquired by us. The system has the ability to deliver crude at Wood River to several other PADD II refineries and pipelines, including those owned by Koch and ConocoPhillips. Movements on the Capwood system are driven by the volumes shipped on Capline as well as Canadian crude that can be delivered to Patoka via the Mustang Pipeline. Since closing, we have assumed the

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operatorship of the Capwood system from SPLC. Since acquisition, throughput on the interest acquired averaged approximately 130,000 barrels per day.

        Mississippi/Alabama Pipeline System.    The Mississippi/Alabama Pipeline System, included in the April 2004 Link transaction, consists of a 331 mile proprietary gathering system and a 355 mile common carrier trunk system delivering crude oil primarily to three local refineries and to the Capline Pipeline System at Liberty, Mississippi. Also included in this system is approximately 4.5 million barrels of storage. Approximately 2.8 million barrels of this storage capacity is located at a deep water terminal in Mobile, Alabama capable of handling tankers with a draft of approximately 37 feet. For the second quarter of 2004, volumes averaged approximately 38,000 barrels per day.

        Southwest Louisiana Pipeline System.    The Southwest Louisiana Pipeline System, included in the April 2004 Link transaction, consists of approximately 254 miles of primarily 6-10" pipe. The system originates in Rapides Parish, Louisiana and delivers to the Citgo refinery in Lake Charles, LA and to Nederland, Texas. For the second quarter of 2004, volumes averaged approximately 7,000 barrels per day.

        Oklahoma Pipeline System.    The Oklahoma Pipeline System, included in the April 2004 Link transaction, consists of approximately 1,354 miles of active pipe, originating at various points in Oklahoma and terminating at Cushing, Oklahoma. In addition to the pipeline, there are approximately 1.7 million barrels of storage included in the system. For the second quarter of 2004, volumes averaged approximately 77,000 barrels per day.

        Midcontinent Pipeline System.    The Midcontinent Pipeline System, included in the April 2004 Link transaction, consists of approximately 1,200 miles of pipe, originating at various points in Nebraska, Kansas, and Colorado. Deliveries are primarily to Jayhawk pipeline and our Oklahoma Pipeline System. Also included in the system are approximately 0.4 million barrels of storage. For the second quarter of 2004, volumes averaged approximately 30,000 barrels per day.

        Cal Ven Pipeline System.    The Cal Ven Pipeline System, acquired in the Cal Ven acquisition in May 2004, is a crude oil pipeline that is located in Northern Alberta, Canada. The Cal Ven Pipeline System is comprised of approximately 195 miles of 8-inch and 10-inch gathering and mainline crude oil pipelines. The Cal Ven Pipeline System delivers crude oil into the Rainbow Pipeline System at Utikuma. At acquisition, the Cal Ven Pipeline System transported approximately 16,000 barrels per day.

        Manito Pipeline System.    The Manito Pipeline System, acquired in the Murphy acquisition, is a provincially regulated system located in Saskatchewan, Canada. The Manito Pipeline System is a 101-mile crude oil pipeline and a parallel 101-mile condensate pipeline that connects our North Saskatchewan Pipeline System and multiple gathering lines to the Enbridge system at Kerrobert. The Manito Pipeline System volumes were approximately 72,000 barrels of crude oil and condensate per day in the first six months of 2004.

        Milk River Pipeline System.    The Milk River Pipeline System, acquired in the Murphy acquisition, is a National Energy Board ("NEB") regulated system located in Alberta, Canada. The Milk River Pipeline System consists of three parallel 11-mile crude oil pipelines that connect the Bow River Pipeline in Alberta to the Cenex Pipeline at the United States border. The Milk River Pipeline System transported approximately 100,000 barrels of crude oil per day during the first six months of 2004.

        North Saskatchewan Pipeline System.    The North Saskatchewan Pipeline System, acquired in the Murphy acquisition, is a provincially regulated system located in Saskatchewan, Canada. We operate the

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North Saskatchewan Pipeline System, which is a 34-mile crude oil pipeline and a parallel 34-mile condensate pipeline that connects to our Manito Pipeline at Dulwich. During the first six months of 2004, the North Saskatchewan Pipeline System delivered approximately 6,200 barrels of crude oil and condensate per day into the Manito Pipeline. Our ownership interest in the North Saskatchewan Pipeline System is approximately 69%.

        Cactus Lake/Bodo Pipeline System.    The Cactus Lake/Bodo Pipeline System, acquired in the Murphy acquisition, is located in Alberta and Saskatchewan, Canada. The Bodo portion of the system is NEB-regulated, and the remainder is provincially regulated. We operate the Cactus Lake/Bodo Pipeline System, which is a 55-mile crude oil pipeline and a parallel 55-mile condensate pipeline that connects to our storage and terminalling facility at Kerrobert. During the first six months of 2004, the Cactus Lake/Bodo Pipeline System transported approximately 25,000 barrels per day (approximately 3,200 barrels per day, net to our interest) of crude oil and condensate. Our ownership interest in the Cactus Lake segment is 15% and our ownership interest in the Bodo Pipeline is 100%. We also own various interests in the lateral lines in these systems.

        Wascana Pipeline System.    The Wascana Pipeline System, acquired in the Murphy acquisition, is an NEB-regulated system located in Saskatchewan, Canada. The Wascana Pipeline System is a 107-mile crude oil pipeline that connects to the Bridger Pipeline system at the United States border near Raymond, Montana. During the first six months of 2004, the Wascana Pipeline System transported approximately 8,000 barrels of crude oil per day.

        Wapella Pipeline System.    The Wapella Pipeline System is a 79 mile, NEB-regulated system located in southeastern Saskatchewan and southwestern Manitoba. During the first six months of 2004, the Wapella Pipeline System delivered approximately 14,000 barrels of crude oil per day to the Enbridge Pipeline at Cromer, Manitoba. The system also includes approximately 18,500 barrels of crude oil storage capacity.

        South Saskatchewan Pipeline System.    The South Saskatchewan Pipeline System, which was acquired in November 2003, originates approximately 75 miles southwest of Swift Current, Saskatchewan, and traverses north and east until it reaches its terminus at Regina. The system consists of a 158-mile, 16-inch mainline and 203 miles of gathering lines ranging in diameter from three to twelve inches. During the first six months of 2004, the system transported approximately 47,000 barrels of crude oil per day. At Regina, the system can deliver crude oil to the Enbridge Pipeline System and to local markets. In addition, the system can indirectly deliver crude oil into our Wascana Pipeline System.


    Gathering, Marketing, Terminalling and Storage Operations

        The combination of our gathering and marketing operations and our terminalling and storage operations provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow. The strategic use of our terminalling and storage assets in conjunction with our gathering and marketing operations provides us with the flexibility to optimize margins irrespective of whether a strong or weak market exists. Following is a description of our activities with respect to this segment.

        Crude Oil.    The majority of our gathering and marketing activities are in the geographic locations previously discussed. These activities include:

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        We purchase crude oil from many independent producers and believe that we have established broad-based relationships with crude oil producers in our areas of operations. Gathering and marketing activities involve relatively large volumes of transactions with lower margins compared to pipeline and terminalling and storage operations.

        The following table shows the average daily volume of our lease gathering and bulk purchases for the past five years and the six months ended June 30, 2004:

 
   
  Year Ended December 31,
 
  Six Months
Ended June 30,
2004

 
  2003
  2002
  2001
  2000
  1999
 
  (barrels in thousands)

Lease gathering   550   437   410   348   262   265
Bulk purchases(1)   136   90   68   46   28   138
   
 
 
 
 
 
  Total volumes   686   527   478   394   290   403
   
 
 
 
 
 

(1)
We have decreased the number of barrels previously disclosed in the "Bulk purchases" line for the 2002 period by approximately 12,000. The adjustment reflects an elimination of crude oil volumes improperly classified as bulk purchases.

        Crude Oil Purchases.    We purchase crude oil from producers under contracts, the majority of which range in term from a thirty-day evergreen to three years. In a typical producer's operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the crude oil is treated to remove water, sand and other contaminants and is then moved into the producer's on-site storage tanks. When the tank is full, the producer contacts our field personnel to purchase and transport the crude oil to market. We utilize our truck fleet and gathering pipelines as well as third party pipelines, trucks and barges to transport the crude oil to market. We own or lease approximately 400 trucks used for gathering crude oil.

        Since 1998, we have had a marketing arrangement with Plains Resources, under which we have been the exclusive marketer and purchaser for all of Plains Resources' equity crude oil production (including its subsidiaries that conduct exploration and production activities). In connection with the separation of Plains Resources and one of its subsidiaries discussed below, Plains Resources divested the bulk of its producing properties. As a result, we do not anticipate the marketing arrangement with Plains Resources to be material to our operating results in the future.

        In December 2002, Plains Resources completed a spin-off to its stockholders of PXP. We currently have a marketing agreement with PXP for the majority of its equity crude oil production and that of its subsidiaries. The marketing agreement provides that we will purchase PXP's equity crude oil production for resale at market prices, for which we charge a fee of $0.20 per barrel. This fee is subject to adjustment every three years based upon then existing market conditions. We are currently negotiating an adjustment to the marketing fee, which we expect to be a downward adjustment. See "Certain Relationships and Related Transactions—Transactions with Related Parties—General."

        Bulk Purchases.    In addition to purchasing crude oil at the wellhead from producers, we purchase crude oil in bulk at major pipeline terminal locations. This oil is transported from the wellhead to the pipeline by major oil companies, large independent producers or other gathering and marketing companies. We purchase crude oil in bulk when we believe additional opportunities exist to realize margins further downstream in the crude oil distribution chain. The opportunities to earn additional margins vary over time with changing market conditions. Accordingly, the margins associated with our bulk purchases will fluctuate from period to period.

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        Crude Oil Sales.    The marketing of crude oil is complex and requires current detailed knowledge of crude oil sources and end markets and a familiarity with a number of factors including grades of crude oil, individual refinery demand for specific grades of crude oil, area market price structures for the different grades of crude oil, location of customers, availability of transportation facilities and timing and costs (including storage) involved in delivering crude oil to the appropriate customer. We sell our crude oil to major integrated oil companies, independent refiners and other resellers in various types of sale and exchange transactions, at market prices for terms ranging from one month to three years.

        We establish a margin for crude oil we purchase by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX and over-the-counter. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. From time to time, we enter into various types of sale and exchange transactions including fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil futures contracts as hedging devices. Except for pre-defined inventory positions, our policy is generally to purchase only crude oil for which we have a market, to structure our sales contracts so that crude oil price fluctuations do not materially affect the segment profit we receive, and to not acquire and hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses. In November 1999, we discovered that this policy was violated, and we incurred $174.0 million in unauthorized trading losses, including associated costs and legal expenses. In 2000, we recognized an additional $7.0 million charge related to the settlement of litigation for an amount in excess of established reserves.

        Crude Oil Exchanges.    We pursue exchange opportunities to enhance margins throughout the gathering and marketing process. When opportunities arise to increase our margin or to acquire a grade of crude oil that more closely matches our physical delivery requirement or the preferences of our refinery customers, we exchange physical crude oil with third parties. These exchanges are effected through contracts called exchange or buy-sell agreements. Through an exchange agreement, we agree to buy crude oil that differs in terms of geographic location, grade of crude oil or physical delivery schedule from crude oil we have available for sale. Generally, we enter into exchanges to acquire crude oil at locations that are closer to our end markets, thereby reducing transportation costs and increasing our margin. We also exchange our crude oil to be physically delivered at a later date, if the exchange is expected to result in a higher margin net of storage costs, and enter into exchanges based on the grade of crude oil, which includes such factors as sulfur content and specific gravity, in order to meet the quality specifications of our physical delivery contracts.

        Producer Services.    Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. Through our team of crude oil purchasing representatives, we maintain ongoing relationships with producers in the United States and Canada. We believe that our ability to offer high-quality field and administrative services to producers is a key factor in our ability to maintain volumes of purchased crude oil and to obtain new volumes. Field services include efficient gathering capabilities, availability of trucks, willingness to construct gathering pipelines where economically justified, timely pickup of crude oil from tank batteries at the lease or production point, accurate measurement of crude oil volumes received, avoidance of spills and effective management of pipeline deliveries. Accounting and other administrative services include securing division orders (statements from interest owners affirming the division of ownership in crude oil purchased by us), providing statements of the crude oil purchased each month, disbursing production proceeds to interest owners, and calculation and payment of ad valorem and production taxes on behalf of interest owners. In order to compete effectively, we must maintain records of title and division order interests in an accurate and timely manner for purposes of making prompt and correct payment of

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crude oil production proceeds, together with the correct payment of all severance and production taxes associated with such proceeds.

        Liquefied Petroleum Gas and Other Petroleum Products.    We also market and store LPG and other petroleum products throughout the United States and Canada, concentrated primarily in Washington, California, Kansas, Michigan, Texas, Montana, Nebraska and the Canadian provinces of Alberta and Ontario. These activities include:

        We purchase LPG from numerous producers and have established long-term, broad-based relationships with LPG producers in our areas of operation. We purchase LPG directly from gas plants, major pipeline terminals and storage locations. Marketing activities for LPG typically consist of smaller volumes and generally higher margin per barrel transactions relative to crude oil.

        LPG Purchases.    We purchase LPG from producers, refiners, and other LPG marketing companies under contracts that range from immediate delivery to one year in term. In a typical producer's or refiner's operation, LPG that is produced at the gas plant or refinery is fractionated into various components including propane and butane and then purchased by us for movement via tank truck, railcar or pipeline.

        In addition to purchasing LPG at gas plants or refineries, we also purchase LPG in bulk at major pipeline terminal points and storage facilities from major oil companies, large independent producers or other LPG marketing companies. We purchase LPG in bulk when we believe additional opportunities exist to realize margins further downstream in our LPG distribution chain. The opportunities to earn additional margins vary over time with changing market conditions. Accordingly, the margins associated with our bulk purchases will fluctuate from period to period.

        LPG Sales.    The marketing of LPG is complex and requires current detailed knowledge of LPG sources and end markets and a familiarity with a number of factors including the various modes and availability of transportation, area market prices and timing and costs of delivering LPG to customers.

        We sell LPG primarily to industrial end users and retailers, and limited volumes to other marketers. Propane is sold to small independent retailers who then transport the product via bobtail truck to residential consumers for home heating and to some light industrial users such as forklift operators. Butane is used by refiners for gasoline blending and as a diluent for the movement of conventional heavy oil production. Butane demand for use as heavy oil diluent has increased as supplies of Canadian condensate have declined.

        We establish a margin for propane by transporting it in bulk, via various transportation modes, to our controlled terminals where we deliver the propane to our retailer customers for subsequent delivery to their individual heating customers. We also create margin by selling propane for future physical delivery to third party users, such as retailers and industrial users. Through these transactions, we seek to maintain a position that is substantially balanced between propane purchases and sales and future delivery obligations. From time to time, we enter into various types of sale and exchange transactions including floating price collar arrangements, financial swaps and crude oil and LPG-related futures contracts as hedging devices. Except for pre-defined inventory positions, our policy is generally to

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purchase only LPG for which we have a market, and to structure our sales contracts so that LPG spot price fluctuations do not materially affect the segment profit we receive. Margin is created on the butane purchased by delivering large volumes during the short refinery blending season through the use of our extensive leased railcar fleet and the use of our own storage facilities and third party storage facilities. We also create margin on butane by capturing the difference in price between condensate and butane when butane is used to replace condensate as a diluent for the movement of Canadian heavy oil production. While we seek to maintain a position that is substantially balanced within our LPG activities, as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions, from time to time we experience net unbalanced positions for short periods of time. In connection with managing these positions and maintaining a constant presence in the marketplace, both necessary for our core business, our policies provide that any net imbalance may not exceed 250,000 barrels. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations.

        LPG Exchanges.    We pursue exchange opportunities to enhance margins throughout the marketing process. When opportunities arise to increase our margin or to acquire a volume of LPG that more closely matches our physical delivery requirement or the preferences of our customers, we exchange physical LPG with third parties. These exchanges are effected through contracts called exchange or buy-sell agreements. Through an exchange agreement, we agree to buy LPG that differs in terms of geographic location, type of LPG or physical delivery schedule from LPG we have available for sale. Generally, we enter into exchanges to acquire LPG at locations that are closer to our end markets in order to meet the delivery specifications of our physical delivery contracts.

        Credit.    Our merchant activities involve the purchase of crude oil for resale and require significant extensions of credit by our suppliers of crude oil. In order to assure our ability to perform our obligations under crude oil purchase agreements, various credit arrangements are negotiated with our crude oil suppliers. These arrangements include open lines of credit directly with us, and standby letters of credit issued under our senior unsecured revolving credit facility.

        When we market crude oil, we must determine the amount, if any, of the line of credit to be extended to any given customer. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures. If we determine that a customer should receive a credit line, we must then decide on the amount of credit that should be extended. Because our typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in our business. We believe our sales are made to creditworthy entities or entities with adequate credit support. Generally, sales of crude oil are settled within 30 days of the month of delivery, and pipeline, transportation and terminalling services also settle within 30 days from invoice for the provision of services.

        We also have credit risk with respect to our sales of LPG; however, because our sales are typically in relatively small amounts to individual customers, we do not believe that we have material concentration of credit risk. Typically, we enter into annual contracts to sell LPG on a forward basis, as well as sell LPG on a current basis to local distributors and retailers. In certain cases our customers prepay for their purchases, in amounts ranging from $0.05 per gallon to 100% of their contracted amounts. Generally, sales of LPG are settled within 30 days of the date of invoice.

        We own approximately 37 million barrels of terminalling and storage assets, including tankage associated with our pipeline and gathering systems. Our storage and terminalling operations increase our margins in our business of purchasing and selling crude oil and also generate revenue through a combination of storage and throughput charges to third parties. Storage fees are generated when we lease tank capacity to third parties. Terminalling fees, also referred to as throughput fees, are generated

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when we receive crude oil from one connecting pipeline and redeliver crude oil to another connecting carrier in volumes that allow the refinery to receive its crude oil on a ratable basis throughout a delivery period. Both terminalling and storage fees are generally earned from:

        The tankage that is used to support our arbitrage activities positions us to capture 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).

        Our most significant terminalling and storage asset is our Cushing Terminal located at the Cushing Interchange. The Cushing Interchange is one of the largest wet-barrel trading hubs in the U.S. and the delivery point for crude oil futures contracts traded on the NYMEX. The Cushing Terminal has been designated by the NYMEX as an approved delivery location for crude oil delivered under the NYMEX light sweet crude oil futures contract. As the NYMEX delivery point and a cash market hub, the Cushing Interchange serves as a primary source of refinery feedstock for the Midwest refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. Our Cushing Terminal was constructed in 1993 to capitalize on the crude oil supply and demand imbalance in the Midwest. The Cushing Terminal is also used to support and enhance the margins associated with our merchant activities relating to our lease gathering and bulk purchasing activities. See "—Gathering and Marketing Operations—Bulk Purchases." In 1999, we completed our 1.1 million barrel Phase I expansion project, which increased the facility's total storage capacity to 3.1 million barrels. On July 1, 2002, we placed in service approximately 1.1 million barrels of tank capacity associated with our Phase II expansion of the Cushing Terminal, raising the facility's total storage capacity to approximately 4.2 million barrels. In January 2003, we placed in service our 1.1 million barrel Phase III expansion, and in July 2004, we completed our Phase IV expansion which increased the total capacity of our Cushing Terminal by 20%. The expansion increased the capacity of the Cushing Terminal to a total of approximately 6.3 million barrels. The Cushing Terminal now consists of fourteen 100,000-barrel tanks, four 150,000-barrel tanks and sixteen 270,000-barrel tanks, all of which are used to store and terminal crude oil. We believe that the facility can be further expanded to meet additional demand should market conditions warrant. The Cushing Terminal also includes a pipeline manifold and pumping system that has an estimated throughput capacity of approximately 800,000 barrels per day. The Cushing Terminal is connected to the major pipelines and other terminals in the Cushing Interchange through pipelines that range in size from 10 inches to 24 inches in diameter.

        The Cushing Terminal is designed to serve the needs of refiners in the Midwest. In order to service an expected increase in the volumes as well as the varieties of foreign and domestic crude oil projected to be transported through the Cushing Interchange, we incorporated certain attributes into the design of the Cushing Terminal including:

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        As a result of incorporating these attributes into the design of the Cushing Terminal, we believe we are favorably positioned to serve the needs of Midwest refiners to handle an increase in the number of varieties of crude oil transported through the Cushing Interchange. The pipeline manifold and pumping system of our Cushing Terminal is designed to support more than 10 million barrels of tank capacity and we have sufficient land holdings in and around the Cushing Interchange on which to construct additional tankage. Our tankage in Cushing ranges in age from less than a year old to approximately 11 years old and the average age is approximately 5.1 years old. In contrast, we estimate that of the approximately 21 million barrels of remaining tanks in Cushing owned by third parties, the average age is approximately 50 years and of that, approximately 9 million barrels has an average age of over 70 years. We believe that provides us with a competitive advantage over our competitors. In addition, we believe that we are well positioned to accommodate construction of replacement tankage that may be required as a result of the imposition of stricter regulatory standards and related attrition among our competitors' tanks in connection with the requirements of API 653. See "—Regulation—Pipeline and Storage Regulation."

        Our Cushing Terminal also incorporates numerous environmental and operational safeguards. We believe that our terminal is the only one at the Cushing Interchange in which each tank has a secondary liner (the equivalent of double bottoms), leak detection devices and secondary seals. The Cushing Terminal is the only terminal at the Cushing Interchange equipped with aboveground pipelines. Like the pipeline systems we operate, the Cushing Terminal is operated by a computer system designed to monitor real-time operational data and each tank is cathodically protected. In addition, each tank is equipped with a high-level alarm system to prevent overflows; a double seal floating roof designed to minimize air emissions and prevent the possible accumulation of potentially flammable gases between fluid levels and the roof of the tank; and a foam dispersal system that, in the event of a fire, is fed by a fully-automated fire water distribution network.

        We also own LPG storage facilities located in Alto, Michigan and Schaefferstown, Pennsylvania. The Alto facility is approximately 20 miles southeast of Grand Rapids. The Alto facility was acquired from Ohio-Northwest Development Inc. in 2003 and is capable of storing over 50 million gallons of LPG. The Schaefferstown facility is approximately 65 miles northwest of Philadelphia. It was acquired from Koch Hydrocarbon, L.P. in September 2004 and is capable of storing over 20 million gallons of propane. We believe these facilities will further support the expansion of our LPG business in Canada and the northern tier of the U.S. as we combine the facilities' existing fee-based storage business with our wholesale propane marketing expertise. In addition, there may be opportunities to expand these facilities as LPG markets continue to develop in the region.

        Crude oil prices have historically been very volatile and cyclical, with NYMEX benchmark prices ranging from as high as approximately $54 per barrel (on October 12, 2004) to as low as $10.00 per barrel over the last 14 years. Segment profit from terminalling and storage activities is dependent on the crude oil throughput volume, capacity leased to third parties, capacity that we use for our own activities, and the level of other fees generated at our terminalling and storage facilities. Segment profit from our gathering and marketing activities is dependent on our ability to sell crude oil at a price in excess of our aggregate cost. Although margins may be affected during transitional periods, these

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operations are not directly affected by the absolute level of crude oil prices, but are affected by overall levels of supply and demand for crude oil and relative fluctuations in market-related indices.

        During periods when supply exceeds the demand for crude oil, the market for crude oil is often in contango, meaning that the price of crude oil for future deliveries is higher than current prices. A contango market has a generally negative impact on marketing margins, but is favorable to the storage business, because storage owners at major trading locations (such as the Cushing Interchange) can simultaneously purchase production at current prices for storage and sell at higher prices for future delivery.

        When there is a higher demand than supply of crude oil in the near term, the market is backwardated, meaning that the price of crude oil for future deliveries is lower than current prices. A backwardated market has a positive impact on marketing margins because crude oil gatherers can capture a premium for prompt deliveries. In this environment, there is little incentive to store crude oil as current prices are above future delivery prices.

        The periods between a backwardated market and a contango market are referred to as transition periods. Depending on the overall duration of these transition periods, how we have allocated our assets to particular strategies and the time length of our crude oil purchase and sale contracts and storage lease agreements, these transition periods may have either an adverse or beneficial affect on our aggregate segment profit. A prolonged transition from a backwardated market to a contango market, or vice versa (essentially a market that is neither in pronounced backwardation nor contango), represents the most difficult environment for our gathering, marketing, terminalling and storage activities. When the market is in contango, we will use our tankage to improve our gathering margins by storing crude oil we have purchased for delivery in future months that are selling at a higher price. In a backwardated market, we use and lease less storage capacity but increased marketing margins 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. References to counter-cyclical balance elsewhere in this report are referring to this relationship between our terminalling and storage activities and our gathering and marketing activities in transitioning crude oil markets.

        As use of the financial markets for crude oil has increased by producers, refiners, utilities and trading entities, risk management strategies, including those involving price hedges using NYMEX futures contracts and derivatives, have become increasingly important in creating and maintaining margins. Such hedging techniques require significant resources dedicated to managing these positions. Our risk management policies and procedures are designed to monitor both NYMEX and over-the-counter positions and physical volumes, grades, locations and delivery schedules to ensure that our hedging activities are implemented in accordance with such policies. We have a risk management function that has direct responsibility and authority for our risk policies, our trading controls and procedures and certain other aspects of corporate risk management.

        Our policy is to purchase only crude oil for which we have a market, and to structure our sales contracts so that crude oil price fluctuations do not materially affect the segment profit we receive. Except for the controlled trading program discussed below, we do not acquire and hold crude oil futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses.

        While we seek to maintain a position that is substantially balanced within our crude oil lease purchase and LPG 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. This controlled trading activity is

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monitored independently by our risk management function and must take place within predefined limits and authorizations.

        In order to hedge margins involving our physical assets and manage risks associated with our crude oil purchase and sale obligations, we use derivative instruments, including regulated futures and options transactions, as well as over-the-counter instruments. In analyzing our risk management activities, we draw a distinction between enterprise-level risks and trading-related risks. Enterprise-level risks are those that underlie our core businesses and may be managed based on whether there is value in doing so. Conversely, trading-related risks (the risks involved in trading in the hopes of generating an increased return) are not inherent in the core business; rather, those risks arise as a result of engaging in the trading activity. We have a Risk Management Committee that approves all new risk management strategies through a formal process. With the partial exception of the controlled trading program, our approved strategies are intended to mitigate enterprise-level risks that are inherent in our core businesses of crude oil gathering and marketing and storage.

        Although the intent of our risk-management strategies is to hedge our margin, not all of our derivatives qualify for hedge accounting. In such instances, changes in the fair values of these derivatives will receive mark-to-market treatment in current earnings, and result in greater potential for earnings volatility than in the past.


Customers

        Marathon Ashland Petroleum accounted for 12%, 10% and 11% of our revenues for each of the three years in the period ended December 31, 2003. For the six months ended June 30, 2004, Marathon Ashland Petroleum and BP Oil Supply Company each accounted for 10% of our revenues. No other customers accounted for 10% or more of our revenues during the three years ended December 31, 2003 or the six months ended June 30, 2004. The majority of the revenues from Marathon Ashland Petroleum and BP Oil Supply Company pertain to our gathering, marketing, terminalling and storage operations. We believe that the loss of these customers would have only a short-term impact on our operating results. There can be no assurance, however, that we would be able to identify and access a replacement market at comparable margins.


Competition

        Competition among pipelines is based primarily on transportation charges, access to producing areas and demand for the crude oil by end users. We believe that high capital requirements, environmental considerations and the difficulty in acquiring rights-of-way and related permits make it unlikely that competing pipeline systems comparable in size and scope to our pipeline systems will be built in the foreseeable future. However, to the extent there are already third-party owned pipelines or owners with joint venture pipelines with excess capacity in the vicinity of our operations, we will be exposed to significant competition based on the incremental cost of moving an incremental barrel of crude oil.

        We face intense competition in our gathering, marketing, terminalling and storage operations. Our competitors include other crude oil pipeline companies, the major integrated oil companies, their marketing affiliates and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours, and control greater supplies of crude oil.


Regulation

        Our operations are subject to extensive regulations. We estimate that we are subject to regulatory oversight by over 70 federal, state, provincial and local departments and agencies, many of which are authorized by statute to issue and have issued laws and regulations binding on the oil pipeline industry,

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related businesses and individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, except for certain exemptions that apply to smaller companies, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of complex federal, state, provincial and local regulations that may affect us, directly or indirectly, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.

        A substantial portion of our petroleum pipelines and storage tanks in the United States are subject to regulation by the U.S. Department of Transportation ("DOT") with respect to the design, installation, testing, construction, operation, replacement and management of pipeline and tank facilities. In addition, we must permit access to and copying of records, and must make certain reports available and provide information as required by the Secretary of Transportation. Comparable regulation exists in Canada and in some states in which we conduct intrastate common carrier or private pipeline operations.

        Federal pipeline safety rules require pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities, and establish pipeline integrity management programs. In particular, since 2000, the DOT has adopted a series of rules requiring operators of interstate pipelines transporting hazardous liquids or natural gas to develop and follow an integrity management program that provides for continual assessment of the integrity of all pipeline segments that could affect so-called "high consequence areas," including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release, and commercially navigable waterways. Segments of our pipelines transporting hazardous liquids in high consequence areas are subject to these DOT rules and therefore obligate us to evaluate pipeline conditions by means of periodic internal inspection, pressure testing, or other equally effective assessment means, and to correct identified anomalies. If, as a result of our evaluation process, we determine that there is a need to provide further protection to high consequence areas, then we will be required to implement additional spill prevention, mitigation and risk control measures for our pipelines. The DOT rules also require us to evaluate and, as necessary, improve our management and analysis processes for integrating available integrity-related data relating to our pipeline segments and to remediate potential problems found as a result of the required assessment and evaluation process. Costs associated with this program were approximately $1.0 million in 2003. Based on currently available information, we estimate that the costs to implement and carry out this program will be approximately $5.6 million in 2004. Our preliminary estimate for 2005 is $5.8 million. The relative increase in program cost for 2004 is primarily attributable to pipeline segments acquired in 2003 and 2004 (including the Link assets), which are subject to the new rules and which were scheduled for assessment in 2004. These costs are recurring in nature and thus will impact future periods. We will continue to refine our estimates as information from our assessments is collected. Our estimates do not include the potential costs associated with assets acquired in the future. Although we believe that our pipeline operations are in substantial compliance with currently applicable regulatory requirements, we cannot predict the potential costs associated with additional, future regulation.

        The DOT is currently considering expanding the scope of its pipeline regulation to include certain gathering pipeline systems that are not currently subject to regulation. This expanded scope would likely include the establishment of additional pipeline integrity management programs for these newly regulated pipelines. The DOT is in the initial stages of evaluating this initiative and we do not currently know what, if any, impact this will have on our operating expenses. However, we cannot assure you that

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future costs related to the potential programs will not be material. However, even if the DOT does not expand the scope of its pipeline regulation to include pipeline systems not currently regulated, we may still need to implement pipeline integrity management programs to remain in compliance with the Federal Water Pollution Control Act and other environmental laws. We could be required to spend substantial sums to ensure the integrity of and upgrade our pipeline systems to maintain environmental compliance, and in some cases, we may take pipelines out of service if we believe the cost of upgrades will exceed the value of the pipelines. We cannot provide any assurance as to the ultimate amount or timing of future pipeline integrity expenditures for environmental compliance.

        States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate.

        The DOT has adopted API 653 as the standard for the inspection, repair, alteration and reconstruction of existing crude oil storage tanks subject to DOT jurisdiction (approximately 83% of our 37 million barrels). API 653 requires regularly scheduled inspection and repair of tanks remaining in service. Full compliance is required by 2009. We have commenced our compliance activities and, based on currently available information, we estimate that we will spend approximately $3 million in 2004 and an approximate average of $6.2 million per year from 2005 through 2009 in connection with API 653 compliance activities. Such amounts incorporate the costs associated with the assets acquired in 2003 and 2004. Our estimates do not include the potential costs associated with assets acquired in the future. We will continue to refine our estimates as information from our assessments is collected.

        We have instituted security measures and procedures, in accordance with DOT guidelines, to enhance the protection of certain of our facilities from terrorist attack. We cannot assure you that these security measures would fully protect our facilities from a concentrated attack. See "—Operational Hazards and Insurance."

        Asset acquisitions are an integral part of our business strategy. As we acquire additional assets, we may be required to incur additional costs in order to ensure that the acquired assets comply with these standards. The timing of such additional costs is uncertain and could vary materially from our current projections.

        General Interstate Regulation.    Our interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines, which includes crude oil, as well as refined product pipelines, be just and reasonable and non-discriminatory.

        State Regulation.    Our intrastate pipeline transportation activities are subject to various state laws and regulations, as well as orders of regulatory bodies.

        Canadian Regulation.    Our Canadian pipeline assets are subject to regulation by the NEB and by provincial agencies. With respect to a pipeline over which it has jurisdiction, each of these agencies has the power, upon application by a third party, to determine the rates we are allowed to charge for transportation on, and set other terms of access to, such pipeline. In such circumstances, if the relevant regulatory agency determines that the applicable terms and conditions of service are not just and reasonable, the agency can amend the offending provisions of an existing transportation contract.

        Energy Policy Act of 1992 and Subsequent Developments.    In October 1992, Congress passed the Energy Policy Act of 1992 ("EP Act"), which among other things, required the FERC to issue rules

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establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing several orders, including Order No. 561. Beginning January 1, 1995, Order No. 561 enables petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made pursuant to the indexing methodology are subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline's filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling unless doing so would reduce a rate "grandfathered" by EP Act (see below) below the grandfathered level. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates, and settlement as alternatives to the indexing approach, which alternatives may be used in certain specified circumstances. The EP Act deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EP Act that had not been subject to complaint, protest or investigation during that 365-day period to be just and reasonable under the Interstate Commerce Act. Generally, complaints against such "grandfathered" rates may only be pursued if the complainant can show either that a substantial change in the economic circumstances of the oil pipeline that were a basis for the rate or in the nature of the services has occurred since the enactment of EP Act, EP Act does not limit a companies ability to challenge a provision of an oil pipeline tariff as unduly discriminatory or preferential.

        On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") issued its opinion in BP West Coast Products, LLC v. FERC, which upheld FERC's determination that the rates of an interstate petroleum products pipeline, SFPP, L.P. ("SFPP"), were grandfathered rates under EP Act and that SFPP's shippers had not demonstrated substantially changed circumstances that would justify modification of those rates. The court also vacated the portion of the FERC's decision applying the Lakehead policy, under which the FERC allowed a regulated entity organized as a master limited partnership to include in its cost-of-service an income tax allowance to the extent that its unit-holders were corporations subject to income tax. We are uncertain what action, if any, FERC will take in response to the court's disapproval of the FERC's Lakehead policy and what effect, if any, such action might have on our rates should they be challenged.

        Additionally, in BP West Coast, the court remanded to the FERC the issue of whether SFPP's revised cost-of-service without a tax allowance would qualify as a substantially changed circumstance that would justify modification of SFPP's rates. Because the court remanded to the FERC and because the FERC's ruling on the substantially changed circumstances issue will focus on the facts and record presented to it, it is not clear what impact, if any, the opinion will have on our rates or on the rates of other FERC-jurisdictional pipelines organized as tax pass-through entities. Moreover, it is not clear to what extent FERC's actions taken in response to BP West Coast will be challenged and, if so, whether they will withstand further FERC or judicial review.

        In a subsequent FERC proceeding involving SFPP, certain shippers again challenged SFPP's grandfathered rates on the basis of substantially changed circumstances since the passage of EP Act. On March 26, 2004, the FERC issued an order in that case, finding that some of SFPP's rates should no longer be grandfathered. Several of the participants in the proceeding have requested rehearing of the FERC's order, and several participants have filed petitions with the D.C. Circuit for review of the order. FERC and court action on those petitions is pending. We are uncertain whether FERC's order will remain intact and, if it does, what effect, if any, that order might have on our grandfathered rates should they be challenged.

        Our Pipelines.    The FERC generally has not investigated rates on its own initiative when those rates have not been the subject of a protest or complaint by a shipper. Substantially all of our segment

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profit on transportation is produced by rates that are either grandfathered or set by agreement of the parties.

        We operate a fleet of trucks to transport crude oil and oilfield materials as a private, contract and common carrier. We are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the Department of Transportation. The trucking regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment, and many other aspects of truck operations. We are also subject to the Occupational Safety and Health Act, as amended ("OSHA"), with respect to our trucking operations.

        Our trucking assets in Canada are subject to regulation by provincial agencies in the provinces in which they are operated. These regulatory agencies do not set freight rates, but do establish and administer rules and regulations relating to other matters including equipment and driver licensing, equipment inspection, hazardous materials and safety.

        As a result of our Canadian acquisitions and cross-border activities, we are subject to regulatory matters including export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Regulations include the Short Supply Controls of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these license, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, the failure to comply with U.S., Canadian, state and local tax requirements could lead to the imposition of additional taxes, interest and penalties.


Environmental, Health and Safety Regulation

        Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons including crude oil are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment. As with the industry generally, compliance with these laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, and even the issuance of injunctions that may restrict or prohibit our operations. Environmental laws and regulations are subject to change, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material affect on our results of operations or earnings. A discharge of hazardous liquids into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and any claims made by neighboring landowners and other third parties for personal injury and property damage.

        The Oil Pollution Act, as amended ("OPA"), was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972, as amended ("Clean Water Act"), and other statutes as they pertain to prevention and response to oil spills. The OPA and analogous state and provincial laws subject owners of facilities to strict, joint and potentially unlimited liability for containment and

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removal costs, natural resource damages, and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the U.S. The OPA establishes a liability limit of $350 million for onshore facilities. However, a party cannot take advantage of this liability limit if the spill is caused by gross negligence or willful misconduct, resulted from a violation of a federal safety, construction, or operating regulation, or if there is a failure to report a spill or cooperate in the cleanup. We believe that we are in substantial compliance with applicable OPA requirements.

        The Clean Water Act and analogous state and provincial laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States and state waters. Permits must be obtained to discharge pollutants into these waters. The Clean Water Act imposes substantial potential liability for the removal and remediation of pollutants. Although we can give no assurances, we believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.

        Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in substantial compliance with any such applicable state requirements.

        In addition to the costs described above we could also be required to spend substantial sums to ensure the integrity of and upgrade our pipeline systems as a result of oil spills, and in some cases, we may take pipelines out of service if we believe the cost of upgrades will exceed the value of the pipelines. We cannot provide any assurance as to the ultimate amount or timing of future pipeline integrity expenditures for environmental compliance.

        Our operations are subject to the Federal Clean Air Act, as amended, and comparable state and provincial laws. We believe that our operations are in substantial compliance with these laws in those areas in which we operate.

        Amendments to the Federal Clean Air Act enacted in 1990 (the "1990 Federal Clean Air Act Amendments") as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas may require most industrial operations in the U.S. to incur capital expenditures in order to meet air emission control standards developed by the U.S. Environmental Protection Agency (the "EPA") and state environmental agencies. The 1990 Federal Clean Air Act Amendments also imposed an operating permit requirement for major sources of air emissions ("Title V permits"), which applies to some of our facilities. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with obtaining or maintaining permits and approvals addressing air emission related issues. Although we can provide no assurance, we believe future compliance with the 1990 Federal Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations.

        We generate wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act ("RCRA") and comparable state and provincial laws. We are not required to comply with a substantial portion of the RCRA requirements because our operations generate primarily oil and gas wastes, which currently are excluded from consideration as RCRA hazardous wastes. However, it is possible that in the future the exclusion of oil and gas wastes from regulation as RCRA hazardous wastes may be eliminated, in which event, our wastes as well as the wastes of our competitors in the oil and gas industry will be subject to more rigorous and costly

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disposal requirements, resulting in additional capital expenditures or operating expenses for us and the industry in general.

        The Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as "Superfund," and comparable state and provincial laws impose liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site or sites where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Under CERCLA, such persons may be subject to strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we may generate waste that falls within CERCLA's definition of a "hazardous substance," in which event, we may be held jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which such hazardous substances have been released into the environment.

        We are subject to the requirements of OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. OSHA has also been given jurisdiction over enforcement of legislation designed to protect employees who provide evidence in fraud cases from retaliation by their employer.

        The federal Endangered Species Act, as amended ("ESA"), restricts activities that may affect endangered species or their habitats. Although certain of our facilities are in areas that may be designated as habitat for endangered species, we believe that we are in substantial compliance with the ESA. However, the discovery of previously unidentified endangered species could cause us to incur additional costs or operation restrictions or bans in the affected area, which costs, restrictions, or bans could have a material adverse effect on our financial condition or results of operations.

        The DOT regulations affecting pipeline safety require pipeline operators to implement measures designed to reduce the environmental impact of oil discharge from onshore oil pipelines. These regulations require operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. In addition, DOT regulations contain detailed specifications for pipeline operation and maintenance. We believe our operations are in substantial compliance with such regulations. See "—Regulation—Pipeline and Storage Regulation."

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        We currently own or lease, and have in the past owned or leased, properties where hazardous liquids, including hydrocarbons, are being or have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, hazardous liquids or associated generated wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hazardous liquids or associated generated wastes was not under our control. These properties and the hazardous liquids or associated generated wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously spilled hazardous liquids or associated generated wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. We are currently involved in remediation activities at a number of sites, which involve potentially significant expense.

        Contamination resulting from spills of liquid hydrocarbons, including crude oil and associated generated wastes, is not unusual within the petroleum pipeline industry. Historic spills along our pipelines as well as at our terminalling and storage facilities as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Properties acquired by us through acquisitions from predecessor operators, such as the properties recently acquired in the Link acquisition, oftentimes have similar impacts to soils and groundwater arising from historical operations on those properties. We are currently addressing site conditions, including soils and groundwater, at a number of our properties, including recently acquired properties, where historical or more recent operations by us or predecessor operators may have resulted in releases of hydrocarbons and other wastes. As of June 30, 2004, we have reserved approximately $23.5 million, of which $15.7 million is related to liabilities assumed as part of the Link acquisition. In addition, we have received contractual protections in the form of environmental indemnifications from several predecessor operators for properties acquired by us that are contaminated as a result of historical operations. These contractual indemnifications typically are subject to specific monetary and term limits that must be satisfied before indemnification will apply.

        For instance, in connection with the Link acquisition, we identified a number of known environmental claims and estimated an amount for potential claims that are currently unknown, for which we received a purchase price reduction from Link. A substantial portion of the known environmental liabilities are associated with the former Texas New Mexico ("TNM") pipeline assets. On the effective date of the acquisition, we and TNM entered into a cost-sharing agreement whereby, on a tiered basis, we will bear $11 million of the first $20 million of pre-May 1999 known environmental issues. We will also bear the first $25,000 per site for unknown sites (capped at 100 sites). TNM will pay all costs in excess of $20 million (excluding the deductible for unknown sites). TNM's obligations are guaranteed by Shell Oil Products.

        In connection with the acquisition of certain Shell crude oil transmissions and gathering assets in 2002, Shell purchased an environmental insurance policy covering known and unknown environmental matters associated with operations prior to closing. We are a named beneficiary under the policy, which has a $100,000 deductible per site, an aggregate coverage limit of $70 million, and expires in 2012. Shell has recently made a claim against the policy; however, we do not believe that the claim will substantially reduce our coverage under the policy.

        Allocation of environmental liability is an issue negotiated in connection with each of our acquisition transactions. In each case, we make an assessment of potential environmental exposure based on available information. Based on that assessment and relevant economic and risk factors, we determine whether to negotiate an indemnity, what the terms of any indemnity should be (for example,

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minimum thresholds or caps on exposure) and whether to obtain insurance, if available. The acquisitions we completed in 2003 or 2004 include a variety of provisions dealing with the allocation of responsibility for environmental costs that range from no or limited indemnities from the sellers to indemnification from sellers with defined limitations on their maximum exposure. We have not obtained insurance for any of the conditions related to our 2003 acquisitions, and only limited circumstances for our 2004 acquisitions. We believe our exposure with respect to the acquired properties is reasonable in light of all the information available to us, but can give no assurance in that regard. To the extent our assessment involves projected costs that are neither indemnified nor insured, we include such costs in our environmental reserve.

        We believe that the environmental reserve described above is adequate, and in conjunction with our indemnification arrangements, should prevent remediation costs from having a material adverse effect on our financial condition, results of operations, or cash flows. Nevertheless, no assurances can be made that any costs incurred in excess of this reserve or outside of the indemnifications would not have a material adverse effect on our financial condition, results of operations, or cash flows.

        Other assets we have acquired or will acquire in the future may have environmental remediation liabilities for which we are not indemnified. We have in the past experienced and in the future will likely experience releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. Although we maintain a program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to environmental releases from our assets may substantially affect our business.


Operational Hazards and Insurance

        Pipelines, terminals or other facilities may experience damage as a result of an accident or natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Since we and our predecessors commenced midstream crude oil activities in the early 1990s, we have maintained insurance of various types and varying levels of coverage that we consider adequate under the circumstances to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable and not excessive. However, such insurance does not cover every potential risk associated with operating pipelines, terminals and other facilities, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Over the last several years, our operations have expanded significantly, with total assets increasing over 300% since the end of 1998. At the same time that the scale and scope of our business activities have expanded, the breadth and depth of the available insurance markets have contracted. Notwithstanding what we believe is a favorable claims history, the overall cost of such insurance as well as the deductibles and overall retention levels that we maintain have increased. As a result, it is anticipated that we will elect to self-insure more activities against certain of these operating hazards. Certain aspects of these conditions were exacerbated by the events of September 11, 2001, and their overall effect on the insurance industry have adversely impacted the availability and cost of certain coverages. Due to these events, insurers have excluded acts of terrorism and sabotage from our insurance policies and on certain of our key assets, we have elected to purchase a separate insurance policy for acts of terrorism and sabotage.

        Since the terrorist attacks, the United States Government has issued numerous warnings that energy assets, including our nation's pipeline infrastructure, may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. We have instituted security measures and procedures in conformity with DOT guidance. We will institute, as appropriate, additional security measures or procedures indicated by the DOT or the Transportation Safety Administration. However, we cannot assure you that these or any other security measures would

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


Title to Properties and Rights-of-Way

        We believe that we have satisfactory title to all of our assets. Although title to such properties are subject to encumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by our predecessor or us, we believe that none of these burdens will materially detract from the value of such properties or from our interest therein or will materially interfere with their use in the operation of our business.

        Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property and, in some instances, such rights-of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases, property for pipeline purposes was purchased in fee. All of the pump stations are located on property owned in fee or property under long-term leases. In certain states and under certain circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.

        Some of the leases, easements, rights-of-way, permits and licenses transferred to us, upon our formation in 1998 and in connection with acquisitions we have made since that time, required the consent of the grantor to transfer such rights, which in certain instances is a governmental entity. We believe that we have obtained such third party consents, permits and authorizations as are sufficient for the transfer to us of the assets necessary for us to operate our business in all material respects as described in this report. With respect to any consents, permits or authorizations that have not yet been obtained, we believe that such consents, permits or authorizations will be obtained within a reasonable period, or that the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business.


Employees

        To carry out our operations, our general partner or its affiliates employed approximately 1,950 employees at June 30, 2004. None of the employees of our general partner were represented by labor unions, and our general partner considers its employee relations to be good.

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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 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. In August 2004, we received a request from the BIS for additional information. We will cooperate with the BIS in its inquiry. 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.

        Alfons Sperber v. Plains Resources Inc., et al.    On December 18, 2003, a putative class action lawsuit was filed in the Delaware Chancery Court, New Castle County, entitled Alfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unitholders, asserts breach of fiduciary duty and breach of contract claims against us, Plains AAP, L.P., and Plains All American GP LLC and its directors, as well as breach of fiduciary duty claims against Plains Resources Inc. and its directors. The complaint seeks to enjoin or rescind a proposed acquisition of all of the outstanding stock of Plains Resources Inc., as well as declaratory relief, an accounting, disgorgement and the imposition of a constructive trust, and an award of damages, fees, expenses and costs, among other things. This lawsuit has been settled in principle, subject to the preparation and execution of appropriate settlement documentation and court approval.

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


Unauthorized Trading Loss

        In November 1999, we discovered that a former employee had engaged in unauthorized trading activity that resulted in significant losses and litigation and had a temporary, but material adverse impact on our liquidity and our relationship with our customers. A full investigation into the unauthorized trading activities by outside legal counsel and independent accountants and consultants determined that the vast majority of the losses occurred in 1999, but also extended into 1998 and required restatements of our financial statements for the applicable periods. Including litigation settlement costs, the aggregate losses associated with this event totaled approximately $181 million. All of the cases were settled and paid. Additionally, based on recommendations from experts involved in the investigation, we made significant enhancements to our systems, policies and procedures and developed and adopted a written policy document and manual of procedures designed to enhance our processes and procedures and improve our ability to detect any activity that might occur at an early stage. We can give no assurance that the above steps will serve to detect and prevent all violations of our trading policy; however, we believe that such steps substantially reduce the possibility of a recurrence of unauthorized trading activities, and that any unauthorized trading that does occur would be detected at an early stage.

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MANAGEMENT

Partnership Management and Governance

        As is the case with many publicly traded partnerships, we do not directly have officers, directors or employees. Our operations and activities are managed by the general partner of our general partner, Plains All American GP LLC, which employs our management and operational personnel. References to our general partner, unless the context otherwise requires, include Plains All American GP LLC. References to our officers, directors and employees are references to the officers, directors and employees of Plains All American GP LLC (or, in the case of our Canadian operations, PMC (Nova Scotia) Company).

        Our general partner manages our operations and activities. Unitholders do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to the unitholders, as limited by our partnership agreement. As a general partner, our general partner is liable for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically non-recourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations on a non-recourse basis.

        Our partnership agreement provides that the general partner will manage and operate us and that, unlike holders of common stock in a corporation, unitholders will have only limited voting rights on matters affecting our business or governance. Specifically, our partnership agreement defines "Board of Directors" to mean the board of directors of Plains All American GP LLC, which is elected by the members of Plains All American GP LLC, and not by the unitholders. Thus, the corporate governance of Plains All American GP LLC is, in effect, the corporate governance of our partnership, subject in all cases to any specific unitholder rights contained in our partnership agreement. Because we are a limited partnership, the new listing standards of the New York Stock Exchange do not require that we or our general partner have a majority of independent directors or a nominating or compensation committee of the board of directors.

        We have an audit committee that reviews our external financial reporting, engages our independent auditors and reviews the adequacy of our internal accounting controls. The Board of Directors has determined that (i) each member of our audit committee is "independent" under applicable New York Stock Exchange Rules and (ii) that each member of our audit committee is an "Audit Committee Financial Expert," as that term is defined in Item 401 of Regulation S-K. The members of our audit committee and other committees are indicated in the table below.

        In determining the independence of the members of our audit committee, the Board of Directors considered the relationships described below:

        Mr. Everardo Goyanes, the Chairman of our Audit Committee, is the Chief Executive Officer of Liberty Energy Corporation ("LEC"), a subsidiary of Liberty Mutual Insurance Company. Mr. Goyanes is an employee of Liberty Mutual Insurance Company. LEC makes investments in producing properties, from some of which Plains Marketing, L.P. buys the production. LEC does not operate the properties in which it invests. Plains Marketing pays the same amount per barrel to LEC that it pays to other interest owners in the properties. In 2003, the amount paid to LEC by Plains Marketing was approximately $1,085,000 ($974,000 net of severance taxes),

        Mr. J. Taft Symonds, a member of our Audit Committee, is a director and the non-executive Chairman of the Board of Tetra Technologies, Inc. ("Tetra"). A subsidiary of Tetra owns crude oil producing properties, from some of which Plains Marketing buys the production. We paid approximately $7.9 million to the Tetra subsidiary in 2003. Until July 2004, Mr. Symonds was also a director of Plains Resources Inc., with whom Plains Marketing has a marketing arrangement. We paid approximately $25.7 million to Plains Resources in 2003, and recognized segment profit of approximately $0.2 million. Mr. Symonds was not and is not an officer of Tetra or Plains Resources,

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and does not participate in operational decision-making, including decisions concerning selection of crude oil purchasers or entering into sales or marketing arrangements.

        We have a compensation committee, which reviews and makes recommendations regarding the compensation for the executive officers and administers our equity compensation plans for officers and key employees. We also have a governance committee that is reviewing and revising our governance practices as appropriate in light of recent governance reform initiatives, which will periodically review our governance guidelines. In addition, our partnership agreement provides for the establishment/activation of a conflicts committee as circumstances warrant to review conflicts of interest between us and our general partner or the owners of our general partner. Such committees would consist of a minimum of two members, none of which are officers or employees of our general partner or directors, officers or employees of its affiliates. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties owed to us or our unitholders.

        Our committee charters and governance guidelines are available on our website at www.paalp.com.


Directors and Executive Officers

        The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner. Directors are elected annually thereafter. Certain owners of our general partner each have the right to separately designate a member of our board. Such designees are indicated in the footnote to the following table.

Name

  Age
  Position with Our General Partner
Greg L. Armstrong(1)   46   Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis   47   President and Chief Operating Officer
Phillip D. Kramer   48   Executive Vice President and Chief Financial Officer
George R. Coiner   53   Senior Group Vice President
W. David Duckett   49   President—PMC (Nova Scotia) Company
Mark F. Shires   47   Senior Vice President—Operations
Alfred A. Lindseth   35   Senior Vice President—Technology, Process & Risk Management
Lawrence J. Dreyfuss   50   Vice President, Associate General Counsel and Assistant Secretary; Vice President, General Counsel and Secretary of PMC (Nova Scotia) Company (the general partner of Plains Marketing Canada, L.P.)
James B. Fryfogle   52   Vice President—Lease Operations
Jim G. Hester   44   Vice President—Acquisitions
Tim Moore   47   Vice President, General Counsel and Secretary
John F. Russell   55   Vice President—Pipeline Operations
Al Swanson   40   Vice President and Treasurer
Tina L. Val   35   Vice President—Accounting and Chief Accounting Officer
Troy E. Valenzuela   43   Vice President—Environmental, Health and Safety
John P. vonBerg   50   Vice President—Trading
David N. Capobianco(1)   35   Director and Member of Compensation Committee
Everardo Goyanes   60   Director and Member of Audit* Committee
Gary R. Petersen(1)   58   Director and Member of Compensation* Committee
John T. Raymond(1)   34   Director
Robert V. Sinnott(1)   55   Director and Member of Compensation Committee
Arthur L. Smith   52   Director and Member of Audit and Governance* Committees
J. Taft Symonds   65   Director and Member of Governance and Audit Committees

*
Indicates chairman of committee

Table continued on following page.

94


(1)
The Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC (as amended, the "LLC Agreement") specifies that the Chief Executive Officer of the general partner will be a member of the board of directors. The LLC Agreement also provides that certain of the owners of our general partner have the right to designate a member of our board of directors. Mr. Petersen has been designated by E-Holdings III, L.P., an affiliate of EnCap Investments L.P., of which he is a Managing Director. Mr. Raymond has been designated by Sable Investments, L.P. Sable Investments, L.P. is controlled by James M. Flores, a director of Vulcan Energy Corporation and also the Chairman, President and Chief Executive Officer of PXP. Mr. Sinnott has been designated by KAFU Holdings, L.P., which is affiliated with Kayne Anderson Investment Management, Inc., of which he is a Vice President. Mr. Capobianco has been designated by Plains Holdings Inc. See "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Beneficial Ownership of General Partner Interest."

        Greg L. Armstrong has served as Chairman of the Board and Chief Executive Officer since our formation. He has also served as a director of our general partner or former general partner since our formation. In addition, he was President, Chief Executive Officer and director of Plains Resources from 1992 to May 2001. He previously served Plains Resources as: President and Chief Operating Officer from October to December 1992; Executive Vice President and Chief Financial Officer from June to October 1992; Senior Vice President and Chief Financial Officer from 1991 to 1992; Vice President and Chief Financial Officer from 1984 to 1991; Corporate Secretary from 1981 to 1988; and Treasurer from 1984 to 1987. Mr. Armstrong is also a director of Varco International, Inc.

        Harry N. Pefanis has served as President and Chief Operating Officer since our formation. He was also a director of our former general partner. In addition, he was Executive Vice President—Midstream of Plains Resources from May 1998 to May 2001. He previously served Plains Resources as: Senior Vice President from February 1996 until May 1998; Vice President—Products Marketing from 1988 to February 1996; Manager of Products Marketing from 1987 to 1988; and Special Assistant for Corporate Planning from 1983 to 1987. Mr. Pefanis was also President of several former midstream subsidiaries of Plains Resources until our formation in 1998.

        Phillip D. Kramer has served as Executive Vice President and Chief Financial Officer since our formation. In addition, he was Executive Vice President and Chief Financial Officer of Plains Resources from May 1998 to May 2001. He previously served Plains Resources as: Senior Vice President and Chief Financial Officer from May 1997 until May 1998; Vice President and Chief Financial Officer from 1992 to 1997; Vice President from 1988 to 1992; Treasurer from 1987 to March 2001; and Controller from 1983 to 1987.

        George R. Coiner has served as Senior Group Vice President since February 2004 and as Senior Vice President from our formation to February 2004. In addition, he was Vice President of Plains Marketing & Transportation Inc., a former midstream subsidiary of Plains Resources from November 1995 until our formation in 1998. Prior to joining Plains Marketing & Transportation Inc., he was Senior Vice President, Marketing with Scurlock Permian Corp.

        W. David Duckett has been President of PMC (Nova Scotia) Company since June 2003, and Executive Vice President of PMC (Nova Scotia) Company from July 2001 to June 2003. Mr. Duckett was previously with CANPET Energy Group Inc. since 1985, where he served in various capacities, including most recently as President, Chief Executive Officer and Chairman of the Board.

        Mark F. Shires has served as Senior Vice President—Operations since June 2003 and as Vice President—Operations from August 1999 to June 2003. He served as Manager of Operations from April 1999 to August 1999. In addition, he was a business consultant from 1996 until April 1999. He served as a consultant to Plains Marketing & Transportation Inc. and Plains All American Pipeline, LP from May 1998 until April 1999. He previously served as President of Plains Terminal & Transfer Corporation, a former midstream subsidiary of Plains Resources, from 1993 to 1996.

        Alfred A. Lindseth has served as Senior Vice President—Technology, Process & Risk Management since June 2003 and as Vice President—Administration from March 2001 to June 2003. He served as Risk Manager from March 2000 to March 2001. He previously served PricewaterhouseCoopers LLP in

95



its Financial Risk Management Practice section as a Consultant from 1997 to 1999 and as Principal Consultant from 1999 to March 2000. He also served GSC Energy, an energy risk management brokerage and consulting firm, as Manager of its Oil & Gas Hedging Program from 1995 to 1996 and as Director of Research and Trading from 1996 to 1997.

        Lawrence J. Dreyfuss has served as Vice President, Associate General Counsel and Assistant Secretary of our general partner since February 2004 and as Associate General Counsel and Assistant Secretary of our general partner from June 2001 to February 2004 and held a senior management position in the Law Department since May 1999. In addition, he was a Vice President of Scurlock Permian LLC from 1987 to 1999.

        James B. Fryfogle has served as Vice President—Lease Operations since July 2004. Prior to joining PAA in January 2004, Mr. Fryfogle served as Manager of Crude Supply and Trading for Marathon Ashland Petroleum. Mr. Fryfogle had held numerous positions of increasing responsibility with Marathon Ashland Petroleum or its affiliates or predecessors since 1975.

        Jim G. Hester has served as Vice President—Acquisitions since March 2002. Prior to joining us, Mr. Hester was Senior Vice President—Special Projects of Plains Resources. From May 2001 to December 2001, he was Senior Vice President—Operations for Plains Resources. From May 1999 to May 2001, he was Vice President—Business Development and Acquisitions of Plains Resources. He was Manager of Business Development and Acquisitions of Plains Resources from 1997 to May 1999, Manager of Corporate Development from 1995 to 1997 and Manager of Special Projects from 1993 to 1995. He was Assistant Controller from 1991 to 1993, Accounting Manager from 1990 to 1991 and Revenue Accounting Supervisor from 1988 to 1990.

        Tim Moore has served as Vice President, General Counsel and Secretary since May 2000. In addition, he was Vice President, General Counsel and Secretary of Plains Resources from May 2000 to May 2001. Prior to joining Plains Resources, he served in various positions, including General Counsel—Corporate, with TransTexas Gas Corporation from 1994 to 2000. He previously was a corporate attorney with the Houston office of Weil, Gotshal & Manges LLP. Mr. Moore also has seven years of energy industry experience as a petroleum geologist.

        John F. Russell has served as Vice President—Pipeline Operations since July 2004. Prior to joining PAA, Mr. Russell served as Vice President of Business Development & Joint Interest for ExxonMobil Pipeline Company. Mr. Russell had held numerous positions of increasing responsibility with ExxonMobil Pipeline Company or its affiliates or predecessors since 1974.

        Al Swanson has served as Vice President and Treasurer since February 2004 and as Treasurer from May 2001 to February 2004. In addition, he held several finance-related positions at Plains Resources including Treasurer from February 2001 to May 2001 and Director of Treasury from November 2000 to February 2001. Prior to joining Plains Resources, he served as Treasurer of Santa Fe Snyder Corporation from 1999 to October 2000 and in various capacities at Snyder Oil Corporation including Director of Corporate Finance from 1998, Controller—SOCO Offshore, Inc. from 1997, and Accounting Manager from 1992. Mr. Swanson began his career with Apache Corporation in 1986 serving in internal audit and accounting.

        Tina L. Val has served as Vice President—Accounting and Chief Accounting Officer since June 2003. She served as Controller from April 2000 until she was elected to her current position. From January 1998 to January 2000, Ms. Val served as a consultant to Conoco de Venezuela S.A. She previously served as Senior Financial Analyst for Plains Resources from October 1994 to July 1997.

        Troy E. Valenzuela has served as Vice President—Environmental, Health and Safety, or EH&S, since July 2002, and has had oversight responsibility for the environmental, safety and regulatory compliance efforts of us and our predecessors for the last 12 years. He was Director of EH&S with Plains Resources from January 1996 to June 2002, and Manager of EH&S from July 1992 to

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December 1995. Prior to his time with Plains Resources, Mr. Valenzuela spent seven years with Chevron USA Production Company in various EH&S roles.

        John P. vonBerg has served as Vice President of Trading since May 2003 and Director of these activities since joining us in January of 2002. He was with Genesis Energy in differing capacities as a Director, Vice Chairman, President and CEO from 1996 through 2001, and from 1993 to 1996 he served as a Vice President and a Crude Oil Manager for Phibro Energy USA. Mr. VonBerg began his career with Marathon Oil Company, spending 13 years in various disciplines.

        David N. Capobianco has served as a director of our general partner since July 2004. Mr. Capobianco is a member of the board of directors of Vulcan Energy Corporation and a Managing Director of Vulcan Capital, an affiliate of Vulcan Inc., where he has been employed since April 2003. Previously, he served as a Vice President of Greenhill Capital from July 2001 to April 2003 and a Vice President of Harvest Partners from July 1995 to January 2001. Mr. Capobianco holds a BA in economics from Duke University and an MBA from Harvard Business School.

        Everardo Goyanes has served as a director of our general partner or former general partner since May 1999. Mr. Goyanes has been President and Chief Executive Officer of Liberty Energy Holdings LLC (an energy investment firm) since May 2000. From 1999 to May 2000, he was a financial consultant specializing in natural resources. From 1989 to 1999, he was Managing Director of the Natural Resources Group of ING Barings Furman Selz (a banking firm). He was a financial consultant from 1987 to 1989 and was Vice President—Finance of Forest Oil Corporation from 1983 to 1987. Mr. Goyanes received a BA in Economics from Cornell University and a Masters degree in Finance (honors) from Babson Institute.

        Gary R. Petersen has served as a director since June 2001. Mr. Petersen co-founded EnCap Investments L.P. (an investment management firm) and has been a Managing Director and principal of the firm since 1988. He had previously served as Senior Vice President and Manager of the Corporate Finance Division of the Energy Banking Group for RepublicBank Corporation. Prior to his position at RepublicBank, he was Executive Vice President and a member of the Board of Directors of Nicklos Oil & Gas Company in Houston, Texas from 1979 to 1984. He served from 1970 to 1971 in the U.S. Army as a First Lieutenant in the Finance Corps and as an Army Officer in the National Security Agency. He is also a director of Equus II Incorporated.

        John T. Raymond has served as a director since June 2001. He has been a director and the Chief Executive Officer of Vulcan Energy Corporation since July 2004. Mr. Raymond has served as President and Chief Executive Officer of Plains Resources since December 2002. Prior thereto, Mr. Raymond served as Executive Vice President and Chief Operating Officer of Plains Resources from May 2001 to November 2001 and President and Chief Operating Officer since November 2001. Mr. Raymond also served as President and Chief Operating Officer of Plains Exploration and Production from December 2002 to March 2004. He was Director of Corporate Development of Kinder Morgan, Inc. from January 2000 to May 2001. He served as Vice President of Corporate Development of Ocean Energy, Inc. from April 1998 to January 2000. He was Vice President of Howard Weil Labouisse Friedrichs, Inc. from 1992 to April 1998.

        Robert V. Sinnott has served as a director of our general partner or former general partner since September 1998. Mr. Sinnott has been a Senior Managing Director of Kayne Anderson Capital Advisors, L.P. (an investment management firm) since 1996, and was a Managing Director from 1992 to 1996. He is also a vice president of Kayne Anderson Investment Management Inc., the general partner of Kayne Anderson Capital Advisors, L.P. He was Vice President and Senior Securities Officer of the Investment Banking Division of Citibank from 1986 to 1992. He is also a director of Glacier Water Services, Inc. (a vended water company). Mr. Sinnott was previously a director of Plains Resources.

97



        Arthur L. Smith has served as a director of our general partner or former general partner since February 1999. Mr. Smith is Chairman and CEO of John S. Herold, Inc. (a petroleum research and consulting firm), a position he has held since 1984. From 1976 to 1984 Mr. Smith was a securities analyst with Argus Research Corp., The First Boston Corporation and Oppenheimer & Co., Inc. Mr. Smith has prior public board experience with Pioneer Natural Resources, Cabot Oil & Gas Corporation and Evergreen Resources, Inc. Mr. Smith holds the CFA designation. He serves on the board of non-profit Dress for Success Houston and the Board of Visitors for the Duke Nicholas School of the Environment and Earth Sciences. Mr. Smith received a BA from Duke University and an MBA from NYU's Stern School of Business.

        J. Taft Symonds has served as a director since June 2001. Mr. Symonds is Chairman of the Board of Symonds Trust Co. Ltd. (an investment firm) and Chairman of the Board of Tetra Technologies, Inc. (an oilfield services firm). From 1978 to 2004 he was Chairman of the Board and Chief Financial Officer of Maurice Pincoffs Company, Inc. (an international marketing firm). Mr. Symonds was previously a director of Plains Resources. Mr. Symonds has a background in both investment and commercial banking, including merchant banking in New York, London and Hong Kong with Paine Webber Jackson & Curtis, Robert Fleming Group and Banque de la Societe Financiere Europeenne. He is a director of Intercorr International and President of the Houston Arboretum and Nature Center. Mr. Symonds received a BA from Stanford University and an MBA from Harvard.

        The following table sets forth certain information with respect to other members of our management team and officers of the general partner of our Canadian operating partnership:

Name

  Age
  Position with Our General
Partner/Canadian General Partner

Management Team/Other Officers:        
 
A. Patrick Diamond

 

31

 

Manager—Special Projects

Canadian Officers:

 

 

 

 
 
D. Mark Alenius

 

45

 

Vice President and Chief Financial Officer of PMC (Nova Scotia) Company
 
Ralph R. Cross

 

49

 

Vice President—Business Development of PMC (Nova Scotia) Company
 
Ronald H. Gagnon

 

46

 

Vice President—Operations of PMC (Nova Scotia) Company
 
M.D. (Mike) Hallahan

 

43

 

Vice President—Crude Oil of PMC (Nova Scotia) Company
 
Ron F. Wunder

 

36

 

Vice President—LPG of PMC (Nova Scotia) Company

        A. Patrick Diamond has served as Manager—Special Projects since June 2001. In addition, he was Manager—Special Projects of Plains Resources from August 1999 to June 2001. Prior to joining Plains Resources, Mr. Diamond served Salomon Smith Barney Inc. in its Global Energy Investment Banking Group as an Associate from July 1997 to May 1999 and as a Financial Analyst from July 1994 to June 1997.

        D. Mark Alenius has served as Vice President and Chief Financial Officer of PMC (Nova Scotia) Company since November 2002. In addition, Mr. Alenius was Managing Director, Finance of PMC (Nova Scotia) Company from July 2001 to November 2002. Mr. Alenius was previously with CANPET Energy Group Inc. where he served as Vice President, Finance, Secretary and Treasurer, and was a member of the Board of Directors. Mr. Alenius joined CANPET in February 2000. Prior to joining

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CANPET Energy, Mr. Alenius briefly served as Chief Financial Officer of Bromley-Marr ECOS Inc., a manufacturing and processing company, from January to July 1999. Mr. Alenius was previously with Koch Industries, Inc.'s Canadian group of businesses, where he served in various capacities, including most recently as Vice-President, Finance and Chief Financial Officer of Koch Pipelines Canada, Ltd.

        Ralph R. Cross has been Vice President of Business Development of PMC (Nova Scotia) Company since July 2001. Mr. Cross was previously with CANPET Energy Group Inc. since 1992, where he served in various capacities, including most recently as Vice President of Business Development.

        Ronald H. Gagnon has been Vice President, Operations of PMC (Nova Scotia) Company since January 2004, Managing Director, Information and Transportation Services from June 2003 to January 2004 and Director, Information Services from July 2001 to May 2003. Mr. Gagnon was previously with CANPET Energy Group Inc. since 1987, where he served in various capacities, including Vice President, Producer Services.

        M.D. (Mike) Hallahan has served as Vice President, Crude Oil of PMC (Nova Scotia) Company since February 2004 and Managing Director, Facilities from July, 2001 to February, 2004. He was previously with CANPET Energy Group inc. where he served in various capacities since 1996, most recently General Manager, Facilities.

        Ron F. Wunder has served as Vice President, LPG of PMC (Nova Scotia) Company since February 2004 and as Managing Director, Crude Oil from July 2001 to February 2004. He was previously with CANPET Energy Group Inc. since 1992, where he served in various capacities, including most recently as General Manager, Crude Oil.


Executive Compensation

        The following table sets forth certain compensation information for our Chief Executive Officer and the four other most highly compensated executive officers in 2003 (the "Named Executive Officers"). Messrs. Armstrong, Pefanis and Kramer were compensated by Plains Resources prior to July 2001. However, we reimburse our general partner and its affiliates (and, for a portion of 2001, we reimbursed our former general partner and its affiliates, which included Plains Resources) for expenses incurred on our behalf, including the costs of officer compensation allocable to us. The Named Executive Officers have also received certain equity-based awards from our general partner and from our former general partner and its affiliates, which awards (other than awards under the Long-Term Incentive Plan) are not subject to reimbursement by us. See "—Long-Term Incentive Plan" and "Certain Relationships and Related Transactions—Transactions with Related Parties."

 
   
  Annual Compensation
  Long-Term
Compensation

Name and
Principal Position

   
   
   
  Other
Compensation

  Year
  Salary
  Bonus
  LTIP Payout
Greg L. Armstrong
Chairman and CEO
  2003
2002
2001
  $

330,000
330,000
165,000


(1)
$

1,000,000
600,000
450,000
  $

12,000
11,000
(2)
(2)
(1)(2)
$
Harry N. Pefanis
President and COO
  2003
2002
2001
  $

235,000
235,000
117,500


(1)
$

800,000
475,000
350,000
  $

12,000
11,000
(2)
(2)
(1)(2)
$ 452,400
Phillip D. Kramer
Executive V.P. and CFO
  2003
2002
2001
  $

200,000
200,000
100,000


(1)
$

500,000
275,000
100,000
  $

12,000
11,000
(2)
(2)
(1)(2)
$
George R. Coiner
Senior Vice President
  2003
2002
2001
  $

200,000
200,000
175,000
  $

719,600
451,000
430,100
(3)
(4)
(5)
$

12,000
11,000
10,500
(2)
(2)
(2)
$ 226,200
W. David Duckett(6)
President—PMC
(Nova Scotia Company)
  2003
2002
2001
  $

190,658
163,891
80,020
  $

724,883
270,070
15,182
  $



  $



Table continued on following page.

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(1)
Salary amounts shown for the year 2001 reflect compensation paid by our general partner and reimbursed by us for the last six months of 2001. Until July 2001, Messrs. Armstrong, Pefanis and Kramer were employed and compensated by Plains Resources, which owned our former general partner. We reimbursed Plains Resources for the portion of their compensation allocable to us. In 2001, approximately $218,000, $655,000 and $127,000 was reimbursed to our former general partner and its affiliates for salary and bonus (for the year 2000) for the services of Messrs. Armstrong, Pefanis and Kramer, respectively. See "Certain Relationships and Related Transactions—Transactions with Related Parties."

(2)
Prior to the transfer of a majority of our general partner interest in 2001 (the "General Partner Transition"), Plains Resources matched 100% of employees' contribution to its 401(k) Plan (subject to certain limitations in the plan), with such matching contribution being made 50% in cash and 50% in Plains Resources Common Stock (the number of shares for the stock match being based on the market value of the Common Stock at the time the shares were granted). After the General Partner Transition, our general partner matches 100% of employees' contributions to its 401(k) Plan in cash, subject to certain limitations in the plan.

(3)
Includes quarterly bonuses aggregating $469,600 and an annual bonus of $250,000. The annual bonus is payable 60% in 2004, 20% in 2005 and 20% in 2006.

(4)
Includes quarterly bonuses aggregating $361,000 and an annual bonus of $90,000. The annual bonus was paid 60% in 2003, and will be paid 20% in 2004 and 20% in 2005.

(5)
Includes quarterly bonuses aggregating $310,100 and an annual bonus of $120,000. The annual bonus was paid 60% in 2002, and 20% in 2003, and 20% will be paid in 2004.

(6)
Salary and bonus for Mr. Duckett are presented in U.S. dollar equivalent, based on the exchange rates in effect on the dates payments were made. Mr. Duckett commenced employment on July 1, 2001.


Employment Contracts and Termination of Employment and Change-in-Control Arrangements

        Messrs. Armstrong and Pefanis have employment agreements with our general partner. Mr. Armstrong is employed as Chairman and Chief Executive Officer. The initial three-year term of Mr. Armstrong's employment agreement expired on June 30, 2004, but was automatically extended for one year in accordance with the agreement. The term will be automatically extended by one year on June 30 of each year unless Mr. Armstrong receives notice from the Chairman of the Compensation Committee that the Board of Directors has elected not to extend the agreement. Mr. Armstrong has agreed, during the term of the agreement and for five years thereafter, not to disclose (subject to typical exceptions) any confidential information obtained by him while employed under the agreement. The agreement provides for a current base salary of $330,000 per year, subject to annual review. If Mr. Armstrong's employment is terminated without cause, he will be entitled to receive an amount equal to his annual base salary plus his highest annual bonus, multiplied by the lesser of (i) the number of years (including fractional years) remaining on the agreement and (ii) two. If Mr. Armstrong terminates his employment as a result of a change in control he will be entitled to receive an amount equal to three times the aggregate of his annual base salary and bonus. Under Mr. Armstrong's agreement, a "change of control" is defined to include (i) the acquisition by an entity or group (other than Plains Resources and its wholly owned subsidiaries) of 50% or more of our general partner or (ii) the existing owners of our general partner ceasing to own more than 50% of our general partner. If Mr. Armstrong's employment is terminated because of his death, a lump sum payment will be paid to his designee equal to his annual salary plus his highest annual bonus, multiplied by the lesser of (i) the number of years (including fractional years) remaining on the agreement and (ii) two. Under the agreement, Mr. Armstrong will be reimbursed for any excise tax due as a result of compensation (parachute) payments.

        Mr. Pefanis is employed as President and Chief Operating Officer. The initial three-year term of Mr. Pefanis' employment agreement expired on June 30, 2004, but was automatically extended for one year in accordance with the agreement. The term will be automatically extended by one year on June 30 of each year unless Mr. Pefanis receives notice from the Chairman of the Board of Directors that the Board has elected not to extend the agreement. Mr. Pefanis has agreed, during the term of the agreement and for one year thereafter, not to disclose (subject to typical exceptions) any confidential

100



information obtained by him while employed under the agreement. The agreement provides for a current base salary of $235,000 per year, subject to annual review. The provisions in Mr. Pefanis' agreement with respect to termination, change in control and related payment obligations are substantially similar to the parallel provisions in Mr. Armstrong's agreement.


1998 Long-Term Incentive Plan

        Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the "LTIP") for employees and directors of our general partner and its affiliates who perform services for us. The LTIP consists of two components, a restricted ("phantom") unit plan and a unit option plan. The LTIP currently permits the grant of phantom units and unit options covering an aggregate of 1,425,000 common units delivered upon vesting of such phantom units or unit options. The plan is administered by the compensation committee of our general partner's board of directors. Our general partner's board of directors in its discretion may terminate the LTIP at any time with respect to any common units for which a grant has not yet been made. Our general partner's board of directors also has the right to alter or amend the LTIP or any part of the plan from time to time, including, subject to any applicable NYSE listing requirements, increasing the number of common units with respect to which awards may be granted; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of such participant.

        Restricted Unit Plan.    A restricted unit is a "phantom" unit that entitles the grantee to receive, upon the vesting of the phantom unit, a common unit (or cash equivalent, depending on the terms of the grant). As discussed in more detail below, a substantial number of phantom units have vested in 2003 and 2004. As of September 30, 2004, giving effect to vested grants, grants of approximately 134,000 unvested phantom units remain outstanding to employees, officers and directors of our general partner. The compensation committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the compensation committee shall determine.

        If a grantee terminates employment or membership on the board for any reason, the grantee's phantom units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Vested phantom units may be satisfied in common units or cash equivalents. Common units to be delivered upon the vesting of rights may be common units acquired by our general partner in the open market or in private transactions, common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. In addition, over the term of the plan we may issue up to 975,000 new common units to satisfy delivery obligations under the grants, less any common units issued upon exercise of unit options under the plan (see below). When we issue new common units upon vesting of the phantom units, the total number of common units outstanding increases. The compensation committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units.

        Other than grants to directors (discussed below), none of the phantom units vested until November 2003. Since that time, approximately 927,000 phantom units have vested. Approximately 381,000 units were issued in satisfaction of those phantom units, after payment of cash-equivalents and netting for taxes. As a result of the vesting of these awards, we recognized an expense of approximately $28.8 million as of December 31, 2003 and an expense of approximately $4.2 million as of June 30, 2004.

        The issuance of the common units pursuant to the restricted unit plan is primarily intended to serve as a means of incentive compensation for performance. Therefore, no consideration is paid to us by the plan participants upon receipt of the common units.

        In 2000, the three non-employee directors of our former general partner (Messrs. Goyanes, Sinnott and Smith) were each granted 5,000 phantom units. These units vested and were paid in connection

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with the transfer of the general partner interest in 2001. Additional grants of 5,000 phantom units were made in 2002 to each non-employee director of our general partner. These units vest and are payable in 25% increments on each anniversary of June 8, 2001. The first three vestings took place on June 8 of 2002, 2003 and 2004. See "—Compensation of Directors."

        The following table shows the vesting of phantom units granted to the Named Executive Officers.

 
   
  November 2003 Vesting
  February 2004
Vesting

  May 2004
Vesting

  August 2004 Vesting
  Remaining
Unvested Grants(2)

Name

  Total
Units

  Units
  Value(1)
  Units
  Value(1)
  Units
  Value(1)
  Units
  Value(1)
  Units
  Value(3)
Greg L. Armstrong   70,000         17,500   $ 551,250   17,500   $ 580,650   17,500   560,700   17,500   $ 629,650
Harry N. Pefanis   70,000   15,000   $ 452,400   47,500   $ 1,511,550   2,500   $ 82,950   2,500   80,100   2,500   $ 89,950
Phillip D. Kramer   50,000         12,500   $ 393,750   12,500   $ 414,750   12,500   400,500   12,500   $ 449,750
George R. Coiner   67,500   7,500   $ 226,200   31,875   $ 1,028,869   9,375   $ 311,063   9,375   300,375   9,375   $ 337,313
W. David Duckett                              

(1)
As of vesting dates.

(2)
With respect to remaining grants, vesting is contingent upon our achieving a specified distribution threshold of $2.50 annualized.

(3)
As if vested on September 30, 2004.

        Unit Option Plan.    The unit option plan under our LTIP currently permits the grant of options covering common units. No grants have been made under the unit option plan to date. However, the compensation committee may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant.

        Upon exercise of a unit option, our general partner may deliver common units acquired by it in the open market or in private transactions or use common units already owned by our general partner, or any combination of the foregoing. In addition, we may issue up to 975,000 new common units to satisfy delivery obligations under the grants, less any common units issued upon vesting of restricted units under the plan. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring such common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, the cost of the unit options will be borne by us. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit to us the proceeds received by it from the optionee upon exercise of the unit option.


Other Equity Grants

        Certain other employees and officers have also received grants of equity not associated with the LTIP described above, and for which we have no cost or reimbursement obligations. For example, our general partner maintains a Performance Option Plan funded by common units owned by the general partner. See "Certain Relationships and Related Transactions—Transactions with Related Parties."


Compensation of Directors

        Each director of our general partner who is not an employee of our general partner is currently paid an annual retainer fee of $45,000, plus reimbursement for out-of-pocket expenses related to meeting attendance. In 2001, Messrs. Goyanes and Smith each received $10,000 for their service on a special committee of the Board of Directors of our former general partner. Mr. Armstrong is otherwise compensated for his services as an employee and therefore receives no separate compensation for his services as a director. Each committee chairman (other than the Audit Committee) receives $2,000

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annually. The chairman of the Audit Committee receives $30,000 annually, and the other members of the Audit Committee receive $15,000 annually. Mr. Petersen assigns any compensation he receives in his capacity as a director to EnCap Energy Capital Fund III, L.P., which is controlled by EnCap Investments L.P., of which Mr. Petersen is a Managing Director. Mr. Capobianco assigns any compensation he receives in his capacity as a director to Vulcan Capital.

        In 2000, Messrs. Goyanes, Sinnott and Smith, as directors of our former general partner, received a grant of 5,000 phantom units each under our LTIP. The phantom units vested and were paid in 2001 in connection with the consummation of the General Partner Transition. Each non-employee director of our general partner received a grant of 5,000 phantom units in 2002. The units vest and are payable in 25% increments annually on each anniversary of June 8, 2001.


Reimbursement of Expenses of Our General Partner and its Affiliates

        We do not pay our general partner a management fee, but we do reimburse our general partner for all expenses incurred on our behalf, including the costs of employee, officer and director compensation and benefits, as well as all other expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Prior to July 1, 2001, an allocation was made for overhead associated with officers and employees who divided time between us and Plains Resources. As a result of the transfer of the general partner interest (and related transactions) in 2001, all of the employees and officers of the general partner devote 100% of their efforts to our business and there are no allocated expenses. See "Certain Relationships and Related Transactions."

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED UNITHOLDERS' MATTERS

Beneficial Ownership of Limited Partner Units

        Our common units, Class B common units and Class C common units outstanding represent 98% of our equity (limited partner interest). The 2% general partner interest is discussed separately below under the caption "Beneficial Ownership of General Partner Interest." The following table sets forth the beneficial ownership of limited partner units held by beneficial owners of 5% or more of the units, by directors and Named Executive Officers of our general partner and by all directors and executive officers as a group as of September 30, 2004.

Name of
Beneficial Owner

  Common Units
  Percentage of
Common Units

  Class B
Common
Units

  Percentage
of Class B
Units

  Class C
Common
Units(12)

  Percentage
of Class C
Common
Units

  Percentage
of Total
Limited
Partner
Units(3)

 
Paul G. Allen(1)   11,084,039   17.7 % 1,307,190   100.0 % 1,298,280   40 % 20.3 %
Plains Resources Inc.(2)   11,084,039   17.7 % 1,307,190   100.0 %     18.4 %
Kayne Anderson Capital Advisors, L.P.(4)   3,147,427   5.0 %     1,460,565   45 % 6.8 %
Tortoise Energy Infrastructure Corporation(5)   763,435   1.2 %     486,855   15 % 1.9 %
Greg L. Armstrong   213,992 (6)(7)(8)   (9)           (9)
Harry N. Pefanis   146,615 (7)(8)   (9)           (9)
George R. Coiner   65,276 (7)(8)   (9)           (9)
Phillip D. Kramer   89,600 (7)(8)   (9)           (9)
W. David Duckett   119,541     (9)          
David N. Capobianco(10)                
Everardo Goyanes   7,450     (9)           (9)
Gary R. Petersen(11)   4,000     (9)           (9)
John T. Raymond(12)   403,117     (9)           (9)
Robert V. Sinnott(13)   13,750     (9)           (9)
Arthur L. Smith   13,750     (9)           (9)
J. Taft Symonds   13,750     (9)           (9)
All directors and executive officers as a group (23 persons)   1,269,375 (7)(8) 2.0 %         1.9 %

(1)
Mr. Allen owns approximately 88.38% of the outstanding shares of common stock of Vulcan Energy Corporation. Vulcan Energy Corporation is the sole stockholder of Plains Resources Inc. See Note 2 below. Mr. Allen is also the sole stockholder and Chairman of the Board of Vulcan Energy II Inc., which is the record holder of 1,298,280 class C common units. The address of Mr. Allen, Vulcan Energy Corporation and Vulcan Energy II Inc. is 505 Fifth Avenue S, Suite 900, Seattle, Washington 98104. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Plains Resources or any of its affiliates.

(2)
Plains Resources Inc. is the sole stockholder of Plains Holdings Inc., our former general partner. The record holder of the common units is Plains Holdings II Inc., a wholly owned subsidiary of Plains Holdings Inc. The record holder of the class B common units is Plains Holdings Inc. The address of Plains Resources Inc., Plains Holdings Inc. and Plains Holdings II Inc. is 700 Milam, Suite 3100, Houston, Texas 77002.

(3)
Limited partner units constitute 98% of our equity, with the remaining 2% held by our general partner. The beneficial ownership of our general partner is set forth in the table below under the caption "Beneficial Ownership of General Partner Interest." Giving effect to the indirect ownership by Plains Resources of a portion of our general partner, Mr. Allen may be deemed to beneficially own approximately 20.8% of our total equity. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Plains Resources or any of its affiliates.

(4)
Various accounts (including KAFU Holdings, L.P., which owns a portion of our general partner) under the management or control of Kayne Anderson Capital Advisors, L.P., the general partner of which is Kayne Anderson Investment Management, Inc., own common units and Class C common units. The address for Kayne Anderson Investment Management Inc. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.

Table continued on following page.

104


(5)
The address of Tortoise Energy Infrastructure Corporation is 10801 Mastin Boulevard, Suite 222, Overland Park, Kansas 66210.

(6)
Does not include the approximately 446,000 common units owned by our general partner, held for the purpose of satisfying its obligations under the Performance Option Plan. Mr. Armstrong disclaims any beneficial ownership of such units beyond his rights as a grantee under the plan.

(7)
Does not include unvested phantom units granted under the 1998 LTIP, none of which will vest within 60 days of the date hereof. See "Executive Compensation—1998 Long-Term Incentive Plan."

(8)
Includes the following vested, unexercised options to purchase common units under the Performance Option Plan. Mr. Armstrong: 37,500; Mr. Pefanis: 27,500; Mr. Coiner: 21,250; Mr. Kramer: 22,500; directors and officers as a group: 161,875.

(9)
Less than one percent.

(10)
The Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC (the "LLC Agreement") specifies that certain of the owners of our general partner have the right to designate a member of our board of directors. Mr. Capobianco has been designated by Plains Holdings Inc., a wholly owned subsidiary of Plains Resources, of which he is a director and Vice President. Mr. Capobianco is also the Vice President of Vulcan Energy II Inc. Mr. Capobianco disclaims any deemed beneficial ownership of our partnership interests held by Plains Resources or any of its affiliates.

(11)
Pursuant to the LLC Agreement, Mr. Petersen has been designated by E-Holdings III, L.P., an affiliate of EnCap Investments L.P., of which he is a Managing Director. Mr. Petersen disclaims any deemed beneficial ownership of any units owned by E-Holdings III, L.P. or other affiliates of EnCap Investments L.P. beyond his pecuniary interest. The address for E-Holdings III, L.P. is 1100 Louisiana, Suite 3150, Houston, Texas 77002.

(12)
Pursuant to the LLC Agreement, Mr. Raymond has been designated one of our directors by Sable Investments, L.P. Sable Investments, L.P. is controlled by James M. Flores, a director of Vulcan Energy Corporation and also the Chairman and Chief Executive Officer of PXP. Mr. Raymond owns approximately 2% of the outstanding shares of common stock of Vulcan Energy Corporation, which owns 100% of Plains Resources. Mr. Raymond is a director and is Chief Executive Officer of Vulcan Energy Corporation. Mr. Raymond disclaims any deemed beneficial ownership of any units held by Sable Holdings, L.P. or its affiliates or Plains Resources or its affiliates.

(13)
Pursuant to the LLC Agreement, Mr. Sinnott has been designated one of our directors by KAFU Holdings, L.P., which is controlled by Kayne Anderson Investment Management, Inc., of which he is a Vice President. Mr. Sinnott disclaims any deemed beneficial ownership of any units held by KAFU Holdings, L.P. or its affiliates, other than through his 4.5% limited partner interest in KAFU Holdings, L.P. The address for KAFU Holdings, L.P. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.

105


Beneficial Ownership of General Partner Interest

        Plains AAP, L.P. owns all of our 2% general partner interest and all of our incentive distribution rights. The following table sets forth the effective ownership of Plains AAP, L.P. (after giving effect to proportionate ownership of GP LLC, its 1% general partner) as of September 30, 2004.

Name and Address of Owner

  Percentage Ownership of
Plains AAP, L.P.

 
Paul G. Allen(1)
505 Fifth Avenue S
Suite 900
Seattle, Washington 98104
  44.000 %

Plains Resources, Inc.(2)
777 Walker, Suite 2400
Houston, Texas 77002

 

44.000

%

Sable Investments, L.P.(2)
700 Milam, Suite 3100
Houston, TX 77002

 

20.000

%

KAFU Holdings, L.P.(3)
1800 Avenue of the Stars, 2nd Floor
Los Angeles, CA 90067

 

16.418

%

E-Holdings III, L.P.(4)
1100 Louisiana, Suite 3150
Houston, TX 77002

 

9.000

%

PAA Management, L.P.(5)
333 Clay Street, #1600
Houston, TX 77002

 

4.000

%

Wachovia Investors, Inc.
301 South College Street, 12th Floor
Charlotte, NC 28288

 

3.382

%

Mark E. Strome
100 Wilshire Blvd., Suite 1500
Santa Monica, CA 90401

 

2.134

%

Strome Hedgecap Fund, L.P.
100 Wilshire Blvd., Suite 1500
Santa Monica, CA 90401

 

1.066

%

(1)
Mr. Allen owns approximately 88.38% of the outstanding shares of common stock of Vulcan Energy Corporation. Vulcan Energy Corporation is the sole stockholder of Plains Resources Inc. Plains Resources Inc. is the sole stockholder of Plains Holdings Inc., which owns 44% of the equity of our general partner. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Plains Resources or any of its affiliates. Sable Investments, L.P. has entered into a voting agreement with Plains Holdings Inc. pursuant to which Sable has agreed to exercise Sable's right to designate a director under the Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC by designating its director in accordance with instructions from Plains Holdings. The agreement is limited to such designations and the obligation to vote in favor of such designee. Either party may terminate the agreement upon 30 days' notice.

(2)
Mr. Capobianco disclaims any deemed beneficial ownership of the interests held by Plains Resources Inc. Mr. Raymond disclaims any deemed beneficial ownership of the interests held by Plains Resources Inc. or any of its affiliates other than through his approximately 2% ownership interest of the outstanding shares of common stock of Vulcan Energy Corporation.

(3)
Mr. Sinnott disclaims any deemed beneficial ownership of the interests owned by KAFU Holdings, L.P. other than through his 4.5% limited partner interest in KAFU Holdings, L.P.

Table continued on following page.

106


(4)
Mr. Petersen disclaims any deemed beneficial ownership of the interests owned by E-Holdings III, L.P. beyond his pecuniary interest.

(5)
PAA Management, L.P. is owned entirely by certain members of senior management, including Messrs. Armstrong (approximately 26%), Pefanis (approximately 14.5%), Kramer (approximately 9.5%), Coiner (approximately 9.5%) and Duckett (approximately 4.5%). Other than Mr. Armstrong, no directors own any interest in PAA Management, L.P. Directors and executive officers as a group own approximately 95% of PAA Management, L.P. Mr. Armstrong disclaims any beneficial ownership of the general partner interest owned by Plains AAP, L.P., other than through his ownership interest in PAA Management, L.P.

        On July 23, 2004, Vulcan Energy acquired all of the outstanding shares of common stock of Plains Resources.

Equity Compensation Plan Information

Plan Category

  Number of units to be
issued upon exercise/vesting
of outstanding options,
warrants and rights*

  Weighted average
exercise price of
outstanding options,
warrants and rights

  Number of units
remaining available
for future issuance
under equity
compensation plans*

 
 
  (a)

  (b)

  (c)

 
Equity compensation plans approved by unitholders:              
1998 Long Term Incentive Plan   133,625 (1) N/A (2) 460,101 (1)(3)
Equity compensation plans not approved by unit holders:              
1998 Long Term Incentive Plan     (1)(4) N/A (2)   (5)
Performance Option Plan     (6) 16.39 (7)   (8)

*
As of September 30, 2004. All unit numbers are rounded to the nearest thousand.

(1)
Our general partner has adopted and maintains a Long Term Incentive Plan for our officers, employees and directors. As originally instituted by our former general partner prior to our initial public offering, the LTIP contemplated issuance of up to 975,000 common units to satisfy awards of phantom units. Upon vesting, these awards could be satisfied either by (i) primary issuance of units by us or (ii) cash settlement or purchase of units by our general partner with the cost reimbursed by us. In 2000, the LTIP was amended, as provided in the plan, without unitholder approval to increase the maximum awards to 1,425,000 phantom units; however, we can issue no more than 975,000 new units to satisfy the awards. Any additional units must be purchased by our general partner in the open market or in private transactions and be reimbursed by us. As of September 30, 2004, we have issued approximately 381,000 common units in satisfaction of vesting under the LTIP. The number of units presented in column (a) assumes that all remaining grants will be satisfied by the issuance of new units upon vesting. In fact, a substantial number of phantom units that vested in 2003 and 2004 were satisfied without the issuance of units. These phantom units were settled in cash or withheld for taxes. See "Management—Long-Term Incentive Plan." Any units not issued upon vesting will become "available for future issuance" under column (c).

(2)
Phantom unit awards under the LTIP vest without payment by recipients. See "Management—Long-Term Incentive Plan—Restricted Unit Plan."

(3)
In accordance with Item 201(d) of Regulation S-K, this column (c) excludes the securities disclosed in column (a). However, as discussed in footnote (1) above, any phantom units represented in column (a) that are not satisfied by the issuance of units become "available for future issuance." See "Management—Long-Term Incentive Plan."

(4)
Although awards for units may from time to time be outstanding under the portion of the LTIP not approved by unitholders, all of these awards must be satisfied in cash or out of units purchased by our general partner and reimbursed by us. None will be satisfied by "units issued upon exercise/vesting."

(5)
Awards for up to 413,750 phantom units may be granted under the portion of the LTIP not approved by unitholders; however, no common units are "available for future issuance" under the plan, because all such awards must be satisfied with cash or out of units purchased by our general partner and reimbursed by us.

Table continued on following page.

107


(6)
Our general partner has adopted and maintains a Performance Option Plan for officers and key employees pursuant to which optionees have the right to purchase units from the general partner. The units that will be sold under the plan were contributed to the general partner by certain of its owners in connection with the General Partner Transition without economic cost to the Partnership. Thus, there will be no units "issued upon exercise/vesting of outstanding options." Approximately 375,000 unit options have been granted out of the 450,000 units originally available under the plan. See footnote (8) below and "Certain Relationships and Related Parties—Transactions with Related Parties—Performance Option Plan."

(7)
As of September 30, 2004, the strike price for all outstanding options under the Performance Option Plan is $16.39 per unit. The strike price decreases as distributions are paid. Future grants may include different pricing elements. See "Certain Relationships and Related Parties—Transactions with Related Parties—Performance Option Plan."

(8)
In connection with the General Partner Transition, certain of the investors in our general partner contributed 450,000 subordinated units (now converted into common units) to our general partner to fund the Performance Option Plan. Options for approximately 372,000 units are currently outstanding and approximately 75,000 units are available for future option grants.

        For a narrative description of the material features of the LTIP and the Performance Option Plan, see "Management—Long-Term Incentive Plan" and "Certain Relationships and Related Transactions—Transactions with Related Parties—Performance Option Plan."

108



CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Our General Partner

        Our operations and activities are managed by, and our officers and personnel are employed by, our general partner (or, in the case of our Canadian operations, PMC (Nova Scotia) Company). Prior to the consummation of the General Partner Transition, some of the senior executives who managed our business also managed and operated the business of Plains Resources. The transition of employment of such executives to our general partner was effected on June 30, 2001. We do not pay our general partner a management fee, but we do reimburse our general partner for all expenses incurred on our behalf.

        Our general partner owns the 2% general partner interest and all of the incentive distribution rights. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 ($1.80 annualized) per unit, 25% of the amounts we distribute in excess of $0.495 ($1.98 annualized) per unit and 50% of amounts we distribute in excess of $0.675 ($2.70 annualized) per unit.

        The following table illustrates the allocation of aggregate distributions at different per-unit levels:

Annual
Distribution Per
Unit

  Distribution to
Unitholders(1)(2)

  Distribution to
GP(1)(2)(3)

  Total Distribution(1)
  GP Percentage
of Total
Distribution

 
$ 1.80   $ 126,000   $ 2,571   $ 128,571   2.0 %
$ 1.98   $ 138,600   $ 4,795   $ 143,395   3.3 %
$ 2.31   $ 161,700   $ 12,495   $ 174,195   7.2 %
$ 2.40   $ 168,000   $ 14,595   $ 182,595   8.0 %
$ 2.60   $ 182,000   $ 19,262   $ 201,262   9.6 %
$ 2.80   $ 196,000   $ 28,595   $ 224,595   12.7 %
$ 3.00   $ 210,000   $ 42,595   $ 252,595   16.9 %

(1)
In thousands.

(2)
Assumes 70,000,000 units outstanding. Actual number of units outstanding as of September 30, 2004 was 67,293,108. An increase in the number of units outstanding would increase both the distribution to unitholders and the distribution to the general partner of any given level of distribution per unit.

(3)
Includes distributions attributable to the 2% general partner interest and the incentive distribution rights.


Transactions with Related Parties

        Before the General Partner Transition, Plains Resources indirectly owned and controlled our former general partner interest. In 2001, our former general partner and its affiliates incurred $31.2 million of direct and indirect expenses on our behalf, which we reimbursed. Of this amount, approximately $218,000, $655,000 and $127,000 represented allocated salary and bonus (for the year 2000) reimbursement for the services of Messrs. Armstrong, Pefanis and Kramer, respectively, as officers of our former general partner.

        As of September 30, 2004 Vulcan Energy, through its wholly owned subsidiary Plains Resources, owned an effective 44% of our general partner interest, as well as approximately 18.4% of our outstanding limited partner units. Mr. John Raymond, one of our directors, is a director and the Chief Executive Officer of Vulcan Energy. Mr. Raymond was designated as a member of our board by Sable Investments, L.P., which is controlled by Mr. James C. Flores. Mr. Flores is a director of Vulcan

109



Energy, the 100% owner of Plains Resources. We have ongoing relationships with Plains Resources. These relationships include but are not limited to:

        On December 18, 2002, Plains Resources completed a spin-off of one of its subsidiaries, PXP, to its shareholders. PXP is a successor participant to the Plains Resources Marketing agreement. For the year ended December 31, 2003, PXP produced approximately 26,000 barrels per day that were subject to the Marketing Agreement. We paid approximately $277.9 million for such production and recognized segment profit of approximately $1.7 million. In our opinion, these purchases were made at prevailing market prices. We are also party to a Letter Agreement with Stocker Resources, L.P. (now PXP) that provides that if the Marketing Agreement terminates before our crude oil sales agreement with Tosco Refining Co. terminates, PXP will continue to sell and we will continue to purchase PXP's equity crude oil production from the Arroyo Grande field (now owned by a subsidiary of PXP) under the same terms as the Marketing Agreement until our Tosco sales agreement terminates. In July 2004, we amended and restated the Marketing Agreement to, among other things, reflect the change in parties as a result of the spin-off. We sell PXP's crude under sales contracts that range from one year to seven years in length. We are currently negotiating an adjustment to the marketing fee, which we expect to be a downward adjustment for new contracts entered into after January 1, 2005.

110



        In connection with our initial public offering, our former general partner, at no cost to us, agreed to transfer, subject to vesting, approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key officers and employees of our former general partner and its affiliates, including Messrs. Armstrong, Pefanis, Coiner and Kramer. Approximately 70,000 units vested in 2000, and the remainder in 2001. The value of the units and associated distribution equivalent rights that vested under the Transaction Grant Agreements for all grantees in 2001 was $5.7 million. Although we recorded noncash compensation expenses with respect to these vestings, the compensation expense incurred in connection with these grants was funded by our former general partner, without reimbursement by us.

        Our general partner has adopted the Plains All American LLC 1998 Long-Term Incentive Plan for employees and directors of our general partner and its affiliates who perform services for us. The LTIP consists of two components, a restricted unit plan and a unit option plan. The LTIP permits the grant of restricted units and unit options covering delivery of an aggregate of 1,425,000 common units. The plan is administered by the compensation committee of our general partner's board of directors.

        A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit (or cash equivalent) upon the vesting of the phantom unit. As of September 30, 2004, approximately 418,000 common units have been issued or purchased and delivered upon vesting and grants of approximately 134,000 phantom units remain outstanding to employees, officers and directors of our general partner. See "Management—Executive Compensation."

        In connection with the General Partner Transition, the owners of the general partner (other than PAA Management, L.P.) contributed an aggregate of 450,000 subordinated units (now converted into common units) to the general partner to provide a pool of units available for the grant of options to management and key employees. In that regard, the general partner adopted the Plains All American 2001 Performance Option Plan, pursuant to which options to purchase approximately 375,000 units have been granted. Of this amount, 75,000, 55,000, 45,000 and 42,500 were granted to Messrs. Armstrong, Pefanis, Kramer and Coiner, respectively, and approximately 346,000 to executive officers as a group. These options vest in 25% increments based upon achieving quarterly distribution levels on our units of $0.525, $0.575, $0.625 and $0.675 ($2.10, $2.30, $2.50 and $2.70, annualized). The first such level was reached in 2002, and 25% of the options vested. The second level was reached in 2004, and an incremental 25% of the options vested. The options will vest in their entirety immediately upon a change in control (as defined in the grant agreements). The original purchase price under the options was $22 per subordinated unit, declining over time in an amount equal to 80% of each quarterly distribution per unit. As of September 30, 2004, the purchase price was $16.39 per unit. The terms of future grants may differ from the existing grants. Because the units underlying the plan were contributed to the general partner, we will have no obligation to reimburse the general partner for the cost of the units upon exercise of the options.

        In connection with the General Partner Transition, certain members of the management team that had been employed by Plains Resources, including Messrs. Armstrong, Pefanis and Kramer, were transferred to the general partner. At that time, such individuals held in-the-money but unvested stock options in Plains Resources, which were subject to forfeiture because of the transfer of employment. Plains Resources, through its affiliates, agreed to substitute a contingent grant of subordinated units, which are now common units pursuant to conversion, with a value equal to the spread on the unvested

111


options, with distribution equivalent rights from the date of grant. The grant included 8,548, 4,602 and 9,742 units to Messrs. Armstrong, Pefanis and Kramer, respectively. The units vest on the same schedule as the stock options would have vested. The units granted to Messrs. Armstrong, Pefanis and Kramer vested in their entirety in 2002. The general partner administers the vesting and delivery of the units under the grants. Because the units necessary to satisfy the delivery requirements under the grants were provided by Plains Resources, we have no obligation to reimburse the general partner for the cost of such units.

        In July 2001, we acquired the assets of CANPET Energy Group Inc., a Calgary-based Canadian crude oil and LPG marketing company (the "CANPET acquisition"), for approximately $24.6 million plus excess inventory at the closing date of approximately $25.0 million. A portion of the purchase price, payable in common units or cash, at our option, was deferred subject to various performance standards being met. On April 30, 2004, we satisfied the deferred payment with the issuance of approximately 385,000 common units (representing approximately $13.1 million in value as of the date of issuance) and the payment of $6.5 million in cash. In addition, an incremental $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. Mr. W. David Duckett, the President of PMC (Nova Scotia) Company, the general partner of Plains Marketing Canada, L.P., owns approximately 37.8% of CANPET, and received a proportionate share of the proceeds from the contingent payment of purchase price for the CANPET assets.

        In connection with the CANPET asset acquisition, Plains Marketing Canada, L.P. assumed CANPET's rights and obligations under a Master Railcar Leasing Agreement between CANPET and Pivotal Enterprises Corporation ("Pivotal"). The agreement provides for Plains Marketing Canada, L.P. to lease approximately 57 railcars from Pivotal at a lease price of $1,000 (Canadian) per month, per car. The lease extends until June of 2008, with an option for Pivotal to extend the term of the lease for an additional five years. Pivotal is substantially owned by former employees of CANPET, including Mr. W. David Duckett. Mr. Duckett owns a 22% interest in Pivotal.

        In April 2004, we sold 3,245,700 unregistered Class C common units (the "Class C common units") to a group of investors comprised of affiliates of Kayne Anderson Capital Advisors, Vulcan Capital and Tortoise Capital pursuant to Rule 4(2) under the Securities Act. For more detailed information with respect to our relationship with Kayne Anderson Capital Advisors and Vulcan Capital, see "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters." We received $30.81 per Class C common unit, an amount which represented 94% of the average closing price of our common units for the twenty trading days immediately ending and including March 26, 2004. Net proceeds from the private placement, including the general partner's proportionate capital contribution and expenses associated with the sale, were approximately $101.0 million. We used the net proceeds from this offering to repay indebtedness under our revolving credit facility incurred in connection with the Link acquisition.

        An affiliate of Wachovia Investors, Inc., which owns a portion of our general partner interest, participated as an underwriter in our December 2003 and July 2004 equity offerings. For the December 2003 offering, they earned approximately $197,000 in net underwriting discounts and commissions. We estimate that they will earn approximately $936,000 in net underwriting discounts and commissions for the July 2004 offering. An affiliate of KAFU Holdings, L.P., another owner of our general partner interest, also participated in our December 2003 and July 2004 equity offerings. In the aggregate for both offerings, they earned approximately $672,000 in commissions for their participation. An affiliate of Wachovia Investors, Inc. is also a lender under our bank credit facility.

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DESCRIPTION OF OUR COMMON UNITS

        Generally, our common units represent limited partner interests that entitle the holders to participate in our cash distributions and to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and our general partner in and to cash distributions. See "Cash Distribution Policy."

        Our outstanding common units are listed on the NYSE under the symbol "PAA." Any additional common units we issue will also be listed on the NYSE.

        The transfer agent and registrar for our common units is American Stock Transfer & Trust Company.


Meetings/Voting

        Each holder of common units is entitled to one vote for each common unit on all matters submitted to a vote of the unitholders.


Status as Limited Partner or Assignee

        Except as described below under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional capital contributions to us.

        Each purchaser of common units offered by this prospectus must execute a transfer application whereby the purchaser requests admission as a substituted limited partner and makes representations and agrees to provisions stated in the transfer application. If this action is not taken, a purchaser will not be registered as a record holder of common units on the books of our transfer agent or issued a common unit certificate. Purchasers may hold common units in nominee accounts.

        An assignee, pending its admission as a substituted limited partner, is entitled to an interest in us equivalent to that of a limited partner with respect to the right to share in allocations and distributions, including liquidating distributions. Our general partner will vote and exercise other powers attributable to common units owned by an assignee who has not become a substituted limited partner at the written direction of the assignee. Transferees who do not execute and deliver transfer applications will be treated neither as assignees nor as record holders of common units and will not receive distributions, federal income tax allocations or reports furnished to record holders of common units. The only right the transferees will have is the right to admission as a substituted limited partner in respect of the transferred common units upon execution of a transfer application in respect of the common units. A nominee or broker who has executed a transfer application with respect to common units held in street name or nominee accounts will receive distributions and reports pertaining to its common units.


Limited Liability

        Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act") and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to some possible exceptions, generally to the amount of capital he is obligated to contribute to us in respect of his units plus his share of any undistributed profits and assets.

        Under the Delaware Act, a limited partnership may not make a distribution to a partner to the extent that at the time of the distribution, after giving effect to the distribution, all liabilities of the partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, exceed the fair value

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of the assets of the limited partnership. For the purposes of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of the property subject to liability of which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act is liable to the limited partnership for the amount of the distribution for three years from the date of the distribution.


Reports and Records

        As soon as practicable, but in no event later than 120 days after the close of each fiscal year, our general partner will furnish or make available to each unitholder of record (as of a record date selected by our general partner) an annual report containing our audited financial statements for the past fiscal year. These financial statements will be prepared in accordance with generally accepted accounting principles. In addition, no later than 45 days after the close of each quarter (except the fourth quarter), our general partner will furnish or make available to each unitholder of record (as of a record date selected by our general partner) a report containing our unaudited financial statements and any other information required by law.

        Our general partner will use all reasonable efforts to furnish each unitholder of record information reasonably required for tax reporting purposes within 90 days after the close of each fiscal year. Our general partner's ability to furnish this summary tax information will depend on the cooperation of unitholders in supplying information to our general partner. Each unitholder will receive information to assist him in determining his U.S. federal and state and Canadian federal and provincial tax liability and filing his U.S. federal and state and Canadian federal and provincial income tax returns.

        A limited partner can, for a purpose reasonably related to the limited partner's interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:

        Our general partner may, and intends to, keep confidential from the limited partners trade secrets and other information the disclosure of which our general partner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.


Class B Common Units

        In connection with our acquisition of Scurlock Permian LLC, in May 1999, we issued 1,307,190 Class B common units for $19.125 per unit in a private placement to our general partner at the time, Plains All American Inc. The Class B common units generally have voting rights that are identical to the voting rights of the common units and vote with the common units as a single class on each matter, except that the Class B common units are not entitled to vote upon the NYSE listing proposals relating

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to the conversion of the Class B common units or Class C common units into common units. Each Class B common unit is entitled to receive 100% of the quarterly amount distributed on each common unit for each quarter. The holder of the Class B common units has the right to demand a unitholder vote on whether the Class B can be converted into common units. We expect the holder to exercise that right on or after October 15, 2004. Assuming the right is exercised on October 15, if our unitholders do not approve the conversion before February 12, 2005, then the terms of the Class B common units will be changed such that each Class B common unit will be entitled to receive 110% of the quarterly amount distributed on each common unit on a pari passu basis with distributions on the common units. If the approval of the conversion is not secured by May 13, 2005, the distribution right increases to 115%. In the event of our dissolution and liquidation, each Class B common unit is entitled to receive 100% of the amount distributed on each common unit.


Class C Common Units

        In connection with the Link acquisition, on April 15, 2004, we issued 3,245,700 Class C common units for $30.81 per unit in a private placement to a group of institutional investors comprised of affiliates of Kayne Anderson Capital Advisers, Vulcan Capital and Tortoise Capital Advisors. The Class C common units generally have voting rights that are identical to the voting rights of the common units and vote with the common units as a single class on each matter, except that the Class C common units are not entitled to vote upon the NYSE listing proposals relating to the conversion of the Class B common units or Class C common units into common units. Each Class C common unit is entitled to receive 100% of the quarterly amount distributed on each common unit for each quarter. The holders of the Class C common units have the right to demand a unitholder vote on whether the Class C can be converted into common units. We expect the holders to exercise that right on or after October 15, 2004. Assuming the right is exercised on October 15, if our unitholders do not approve the conversion before February 12, 2005, then the terms of the Class C common units will be changed such that each Class C common unit will be entitled to receive 110% of the quarterly amount distributed on each common unit on a pari passu basis with distributions on the common units. If the approval of the conversion is not secured by May 13, 2005, the distribution right increases to 115%. In the event of our dissolution and liquidation, each Class C common unit is entitled to receive 100% of the amount distributed on each common unit.

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CASH DISTRIBUTION POLICY

Distributions of Available Cash

        General.    We will distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below.

        Definition of Available Cash.    Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:


Operating Surplus and Capital Surplus

        General.    Cash distributions to our unitholders will be characterized as either operating surplus or capital surplus. We distribute available cash from operating surplus differently than available cash from capital surplus. See "—Quarterly Distributions of Available Cash."

        Definition of Operating Surplus.    Operating surplus refers generally to:

        Definition of Capital Surplus.    Capital surplus will generally be generated only by:

        We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began equals the operating surplus as of the end of the quarter prior to the distribution. Any available cash in excess of operating surplus, regardless of its source, will be treated as capital surplus.

        If we distribute available cash from capital surplus for each common unit in an aggregate amount per common unit equal to the initial public offering price of the common units, there will not be a distinction between operating surplus and capital surplus, and all distributions of available cash will be treated as operating surplus. We do not anticipate that we will make distributions from capital surplus.


Incentive Distribution Rights

        The incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution

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and the target distribution levels have been achieved. The target distribution levels are based on the amounts of available cash from operating surplus distributed above the payments made under the minimum quarterly distribution, if any, and the related 2% distribution to the general partner.


Effect of Issuance of Additional Units

        We can issue additional common units or other equity securities for consideration and under terms and conditions approved by our general partner in its sole discretion and without the approval of our unitholders. We may fund acquisitions through the issuance of additional common units or other equity securities.

        Holders of any additional common units that we issue will be entitled to share equally with our then-existing unitholders in distributions of available cash. In addition, the issuance of additional interests may dilute the value of the interests of the then-existing unitholders. If we issue additional partnership interests, our general partner will be required to make an additional capital contribution to us or the operating partnership.


Quarterly Distributions of Available Cash

        We will make quarterly distributions to our partners prior to our liquidation in an amount equal to 100% of our available cash for that quarter. We expect to make distributions of all available cash within approximately 45 days after the end of each quarter to holders of record on the applicable record date. The minimum quarterly distribution and the target distribution levels are also subject to certain other adjustments as described below under "—Distributions from Capital Surplus" and "—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels."


Distributions From Operating Surplus

        We will make distributions of available cash from operating surplus in the following manner:


Incentive Distribution Rights

        For any quarter that we distribute available cash from operating surplus to the common unitholders in an amount equal to the minimum quarterly distribution on all units, then we will distribute any additional available cash from operating surplus in that quarter among the unitholders and the general partner in the following manner:

        Our distributions to the general partner above, other than in its capacity as holders of units, that are in excess of its aggregate 2% general partner interest represent the incentive distribution rights. The right to receive incentive distribution rights is not part of its general partner interest and may be transferred separately from that interest, subject to certain restrictions.

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Distributions from Capital Surplus

        How Distributions from Capital Surplus Will Be Made.    We will make distributions of available cash from capital surplus in the following manner:

        Effect of a Distribution from Capital Surplus.    Our partnership agreement treats a distribution of available cash from capital surplus as the repayment of the initial unit price. To show that repayment, the minimum quarterly distribution and the target distribution levels will be reduced by multiplying each amount by a fraction, the numerator of which is the unrecovered capital of the common units immediately after giving effect to that repayment and the denominator of which is the unrecovered capital of the common units immediately prior to that repayment.

        When Payback Occurs.    When "payback" of the reduced initial unit price has occurred, i.e., when the unrecovered capital of the common units is zero, and then

        Distributions of available cash from capital surplus will not reduce the minimum quarterly distribution or target distribution levels for the quarter in which they are distributed.


Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        How We Adjust the Minimum Quarterly Distribution and Target Distribution Levels.    In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units (but not if we issue additional common units for cash or property), we will proportionately adjust:

        For example, in the event of a two-for-one split of the common units (assuming no prior adjustments), the minimum quarterly distribution, each of the target distribution levels and the unrecovered capital of the common units would each be reduced to 50% of its initial level.

        If We Became Subject to Taxation.    If legislation is enacted or if existing law is modified or interpreted by the relevant governmental authority so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce

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the minimum quarterly distribution and the target distribution levels to an amount equal to the product of:

        For example, assuming we were not previously subject to state and local income tax, if we become taxable as an entity for federal income tax purposes and became subject to a maximum marginal federal, and effective state and local, income tax rate of 38%, then the minimum quarterly distribution and the target distribution levels would each be reduced to 62% of the amount immediately prior to that adjustment.


Distribution of Cash Upon Liquidation

        General.    If we dissolve and liquidate, we will sell our assets or otherwise dispose of our assets and we will adjust the partners' capital account balances to show any resulting gain or loss. We will first apply the proceeds of liquidation to the payment of our creditors in the order of priority provided in our partnership agreement and by law and, thereafter, distribute to the unitholders and the general partner in accordance with their adjusted capital account balances.

        Manner of Adjustment.    If we liquidate, we would allocate any loss to the general partner and each unitholder as follows:

        Interim Adjustments to Capital Accounts.    If we issued additional security interests or made distributions of property, interim adjustments to capital accounts would also be made. These adjustments would be based on the fair market value of the interests or the property distributed and any gain or loss would be allocated to the unitholders and the general partner in the same way that a gain or loss is allocated upon liquidation. If positive interim adjustments are made to the capital accounts, any subsequent negative adjustments to the capital accounts resulting from our issuance of additional interests, distributions of property, or upon our liquidation, would be allocated in a way that, to the extent possible, in the capital account balances of the general partner equaling the amount which would have been the general partner's capital account balances if no prior positive adjustments to the capital accounts had been made.

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DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

        The following is a summary of the material provisions of our partnership agreement. The following provisions of our partnership agreement are summarized elsewhere in this prospectus:


Purpose

        Our purpose under our partnership agreement is to serve as a partner of our operating partnerships and to engage in any business activities that may be engaged in by our operating partnerships or that is approved by our general partner. The partnership agreements of our operating partnerships provide that they may engage in any activity that was engaged in by our predecessors at the time of our initial public offering or reasonably related thereto and any other activity approved by our general partner.


Power of Attorney

        Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants the authority for the amendment of, and to make consents and waivers under, our partnership agreement.


Reimbursements of Our General Partner

        Our general partner does not receive any compensation for its services as our general partner. It is, however, entitled to be reimbursed for all of its costs incurred in managing and operating our business. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion.


Issuance of Additional Securities

        Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities that are equal in rank with or junior to our common units on terms and conditions established by our general partner in its sole discretion without the approval of any limited partners.

        It is likely that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our cash distributions. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

        In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion of our general partner, may have special voting rights to which common units are not entitled.

        Our general partner has the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent

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necessary to maintain their percentage interests in us that existed immediately prior to the issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests in us.


Amendments to Our Partnership Agreement

        Amendments to our partnership agreement may be proposed only by our general partner. Any amendment that materially and adversely affects the rights or preferences of any type or class of limited partner interests in relation to other types or classes of limited partner interests or our general partner interest will require the approval of at least a majority of the type or class of limited partner interests or general partner interests so affected. However, in some circumstances, more particularly described in our partnership agreement, our general partner may make amendments to our partnership agreement without the approval of our limited partners or assignees.


Withdrawal or Removal of Our General Partner

        Our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2008 without obtaining the approval of the holders of a majority of our outstanding common units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2008, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days' notice to our limited partners if at least 50% of our outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates.

        Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of our outstanding units, excluding the common units held by the withdrawing general partner and its affiliates agree to continue our business and to appoint a successor general partner.

        Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than two-thirds of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of a majority of our outstanding common units, including those held by our general partner and its affiliates.

        While our partnership agreement limits the ability of our general partner to withdraw, it allows the general partner interest and incentive distribution rights to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of our general partner.

        In addition, our partnership agreement expressly permits the sale, in whole or in part, of the ownership of our general partner. Our general partner may also transfer, in whole or in part, the common units it owns.


Liquidation and Distribution of Proceeds

        Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general

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partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:

        Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to our partners, our general partner may distribute assets in kind to our partners.


Change of Management Provisions

        Our partnership agreement contains the following specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change management:


Limited Call Right

        If at any time our general partner and its affiliates own 80% or more of the issued and outstanding limited partner interests of any class, our general partner will have the right to purchase all, but not less than all, of the outstanding limited partner interests of that class that are held by non-affiliated persons. The record date for determining ownership of the limited partner interests would be selected by our general partner on at least 10 but not more than 60 days' notice. The purchase price in the event of a purchase under these provisions would be the greater of (1) the current market price (as defined in our agreement) of the limited partner interests of the class as of the date three days prior to the date that notice is mailed to the limited partners as provided in our partnership agreement and (2) the highest cash price paid by our general partner or any of its affiliates for any limited partner interest of the class purchased within the 90 days preceding the date our general partner mails notice of its election to purchase the units.


Indemnification

        Under our partnership agreement, in most circumstances, we will indemnify our general partner, its affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to our best interest. Any indemnification under these provisions will only be out of our assets. Our general partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate any indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

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Registration Rights

        Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

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TAX CONSIDERATIONS

        This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, expresses the opinion of Vinson & Elkins L.L.P., special counsel to the general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters.

        This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.

        No attempt has been made in the following discussion to comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we recommend that each prospective unitholder consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

        All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of counsel and are based on the accuracy of the factual representations made by us.

        No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. An opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the treatment of us, or an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

        For the reasons described below, counsel has not rendered an opinion with respect to the following specific federal income tax issues:


Partnership Status

        A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are

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generally not taxable unless the amount of cash distributed is in excess of the partner's adjusted basis in his partnership interest.

        No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating partnerships as partnerships for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Code. Instead, we will rely on the opinion of counsel that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we and the operating partnerships will be classified as a partnership for federal income tax purposes.

        In rendering its opinion, counsel has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which counsel has relied are:

        Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the "Qualifying Income Exception," exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the transportation and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, counsel is of the opinion that at least 90% of our current gross income constitutes qualifying income.

        If we fail to meet the Qualifying Income Exception, other than a failure which is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

        If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder's tax basis in his common units, or taxable capital gain, after the unitholder's tax basis in his common units has been reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

        The discussion below is based on the conclusion that we will be classified as a partnership for federal income tax purposes.

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Limited Partner Status

        Unitholders who have become limited partners of Plains All American Pipeline will be treated as partners of Plains All American Pipeline for federal income tax purposes. Also:

will be treated as partners of Plains All American Pipeline for federal income tax purposes. As there is no direct authority addressing assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, counsel's opinion does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

        A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read "—Tax Consequences of Unit Ownership—Treatment of Short Sales."

        Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders should consult their own tax advisors with respect to their status as partners in Plains All American Pipeline for federal income tax purposes.


Tax Consequences of Unit Ownership

        Flow-through of Taxable Income.    We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by that unitholder. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year.

        Treatment of Distributions.    Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder's tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. Any reduction in a unitholder's share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder's "at risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."

        A decrease in a unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a

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corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder's share of our "unrealized receivables," including depreciation recapture, and/or substantially appreciated "inventory items," both as defined in Section 751 of the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder's realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder's tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

        Basis of Common Units.    A unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder's share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A limited partner will have no share of our debt which is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

        Limitations on Deductibility of Losses.    The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be "at risk" with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations will no longer utilizable.

        In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder's at risk amount will increase or decrease as the tax basis of the unitholder's units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

        The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly-traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder's share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity

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loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

        A unitholder's share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

        Limitations on Interest Deductions.    The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:


        The computation of a unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income from a publicly-traded partnership will be treated as investment income for purposes of the limitations on the deductibility of investment interest. In addition, the unitholder's share of our portfolio income will be treated as investment income.

        Entity-Level Collections.    If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

        Allocation of Income, Gain, Loss and Deduction.    In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that incentive distributions are made to the general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

        Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by the general partner, referred to in this discussion as "Contributed Property," and to account for the difference between the fair market value of our assets and their carrying value on our books at the time of an offering. The effect of these allocations to a unitholder purchasing common units in an offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of

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the offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

        An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and "tax" capital account, credited with the tax basis of Contributed Property referred to in this discussion as the "Book-Tax Disparity", will generally be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner's share of an item will be determined on the basis of the partner's interest in us, which will be determined by taking into account all the facts and circumstances, including the partner's relative contributions to us, the interests of all the partners in profits and losses, the interest of all the partners in cash flow and other nonliquidating distributions and rights of the partners to distributions of capital upon liquidation.

        Counsel is of the opinion that, with the exception of the issues described in "—Tax Consequences of Unit Ownership—Section 754 Election" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," respectively, allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner's share of an item of income, gain, loss or deduction.

        Treatment of Short Sales.    A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

        Counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to ensure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please read "—Disposition of Common Units—Recognition of Gain or Loss."

        Alternative Minimum Tax.    Although it is not expected that we will generate significant tax preference items or adjustments, each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders should consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

        Tax Rates.    In general the highest effective United States federal income tax rate for individuals currently is 35% and the maximum United States federal income tax rate for net capital gains of an

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individual currently is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

        Section 754 Election.    We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other partners. For purposes of this discussion, a partner's inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that basis.

        Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-l(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read "—Tax Treatment of Operations" and "—Uniformity of Units."

        Although counsel is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Units."

        A Section 754 election is advantageous if the transferee's tax basis in his units is higher than the units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and a smaller share of any gain or loss on a sale of our assets. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his units is lower than those units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

        The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The determinations we make may be successfully challenged by the IRS and the deductions resulting from them may be reduced or disallowed altogether. For example, the allocation of the Section 743(b) adjustment among our assets

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must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.


Tax Treatment of Operations

        Accounting Method and Taxable Year.    We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."

        Initial Tax Basis, Depreciation and Amortization.    The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by partners holding interests in us prior to this offering. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction."

        To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

        If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."

        The costs incurred in selling our units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

        Valuation and Tax Basis of Our Properties.    The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of

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items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and may incur interest and penalties with respect to those adjustments.


Disposition of Common Units

        Recognition of Gain or Loss.    Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder's tax basis for the units sold. A unitholder's amount realized will be measured by the sum of the cash or the fair market value of other property received plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

        Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder's tax basis in that common unit, even if the price is less than his original cost.

        Except as noted below, gain or loss recognized by a unitholder, other than a "dealer" in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed a maximum rate of 15%. A portion of this gain or loss, which will likely be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other "unrealized receivables" or to "inventory items" we own. The term "unrealized receivables" includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income in the case of individuals, and may only be used to offset capital gains in the case of corporations.

        The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method. Although the ruling is unclear as to how the holding period of these interests is determined once they are combined, Treasury regulations allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions should consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

        Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated" partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

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        Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

        Allocations Between Transferors and Transferees.    In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the NYSE on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

        The use of this method may not be permitted under existing Treasury regulations. Accordingly, counsel is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders to conform to a method permitted under future Treasury Regulations.

        A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

        Notification Requirements.    A unitholder who sells or exchanges units is required to notify us in writing of that sale or exchange within 30 days after the sale or exchange. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Additionally, a transferor and a transferee of a unit will be required to furnish statements to the IRS, filed with their income tax returns for the taxable year in which the sale or exchange occurred, that describe the amount of the consideration received for the unit that is allocated to our goodwill or going concern value. Failure to satisfy these reporting obligations may lead to the imposition of substantial penalties.

        Constructive Termination.    We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

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Uniformity of Units

        Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read "—Tax Consequences of Unit Ownership—Section 754 Election."

        We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 even though that portion may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Unit Ownership—Section 754 Election." To the extent that the Section 743 (b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."


Tax-Exempt Organizations and Other Investors

        Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder which is a tax-exempt organization will be unrelated business taxable income and will be taxable to the unitholder.

        A regulated investment company or "mutual fund" is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.

        Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction

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and pay federal income tax at regular rates on their share of our income or gain. And, under rules applicable to publicly traded partnerships, we will withhold tax at the highest effective applicable rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes.

        In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a "qualified resident." In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

        Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the disposition.


Administrative Matters

        Information Returns and Audit Procedures.    We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine the unitholder's share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

        The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year's tax liability, and possibly may result in an audit of that unitholder's own return. Any audit of a unitholder's return could result in adjustments not related to our returns as well as those related to our returns.

        Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. The partnership agreement appoints the general partner as our Tax Matters Partner.

        The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership

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administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate. However, if we elect to be treated as a large partnership, a unitholder will not have the right to participate in settlement conferences with the IRS or to seek a refund.

        A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of the consistency requirement may subject a unitholder to substantial penalties. However, if we elect to be treated as a large partnership, the unitholders would be required to treat all partnership items in a manner consistent with our return.

        Nominee Reporting.    Persons who hold an interest in us as a nominee for another person are required to furnish to us:

        Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

        Registration as a Tax Shelter.    The Internal Revenue Code requires that "tax shelters" be registered with the Secretary of the Treasury. It is arguable that we are not subject to the registration requirement on the basis that we will not constitute a tax shelter. However, we have registered as a tax shelter with the Secretary of Treasury in the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which might be imposed if registration is required and not undertaken.

        Issuance of this registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.

        Our tax shelter registration number is 99061000009. A unitholder who sells or otherwise transfers a unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.

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        Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a "reportable transaction." Unitholders may be required to file this form with the IRS if we participate in a "reportable transaction." A transaction may be a reportable transaction based upon any of several factors. Unitholders are urged to consult with their own tax advisor concerning the application of any of these factors to their investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on "material advisors" that organize, manage or sell interests in registered "tax shelters." As stated above, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including unitholder names and tax identification numbers, and to furnish this information to the IRS upon request. Unitholders are urged to consult with their own tax advisor concerning any possible disclosure obligation with respect to their investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

        Accuracy-related Penalties.    An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

        A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

        More stringent rules apply to "tax shelters," a term that in this context does not appear to include us. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an "understatement" of income for which no "substantial authority" exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.

        A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.


State, Local and Other Tax Considerations

        In addition to federal income taxes, you may be subject to other taxes, such as state and local and Canadian federal and provincial taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property. Although an analysis of those various taxes is not presented herein, each prospective unitholder should consider their potential impact on his investment in us. We will own property or conduct business in Canada and in most states of the United States. A unitholder may be required to

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file Canadian federal income tax returns and to pay Canadian federal and provincial income taxes and to file state income tax returns and to pay taxes in various states and may be subject to penalties for failure to comply with such requirements. In certain states, tax losses may not produce a tax benefit in the year incurred (if, for example, we have no income from sources within that state) and also may not be available to offset income in subsequent taxable years. Some of the states may require us to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder's income tax liability to the state, generally does not relieve the non-resident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amount distributed by us. Please read "—Tax Consequences of Unit Ownership." We may also own additional property or do business in other states in the future.

        It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, including the Canadian provinces and Canada, of his investment in us. Accordingly, each prospective unitholder should consult, and must depend upon, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all Canadian, Canadian province, state and local, as well as federal tax returns that may be required of him. Counsel has not rendered an opinion on the Canadian federal, Canadian provincial, state or local tax consequences of an investment in us.

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SELLING UNITHOLDERS

        This prospectus covers the offering for resale of up to 3,245,700 common units by selling unitholders. These common units are issuable upon the conversion of our outstanding Class C common units. The Class C common units will not be eligible for conversion into common units until such conversion has been approved by a vote of our common unitholders. It is currently anticipated that this approval will be received at a special meeting of our unitholders to be held in early 2005. No selling unitholder may offer or sell our common units under this prospectus unless the conversion of the Class C common units into common units has been approved by our common unitholders. In addition, no such sales may occur unless the selling unitholder has notified us of his or her intention to sell our common units and this prospectus has been declared effective by the SEC, and remains effective at the time such selling unitholder offers or sells such common units. We are required to update this prospectus to reflect material developments in our business, financial position and results of operations. The following table sets forth information relating to the selling unitholders' beneficial ownership of our Class C common units and the common units into which they may be convertible. Additional information with respect to the holders of the Class C common units is contained in this prospectus under the caption "Security Ownership of Certain Beneficial Owners and Management and Related Unitholders Matters."

Selling Unitholders

  Number of
Class C
Common Units
Beneficially Owned

  Number of
Common Units
Offered
Hereunder

  Number and Percentage of
Common Units to be Owned
Following Completion of
this Offering

Kayne Anderson Capital Advisors, L.P.(1)   1,460,565   1,460,565   3,147,427/6.8%
Vulcan Energy II Inc.(2)   1,298,280   1,298,280  
Tortoise Energy Infrastructure Corporation   486,855   486,855   763,435/1.2%

(1)
Various accounts (including KAFU Holdings, L.P., which owns a portion of our general partner) under the management or control of Kayne Anderson Capital Advisors, L.P., the general partner of which is Kayne Anderson Investment Management, Inc., own common units and Class C common units. Mr. Sinnott, a Vice President of Kayne Anderson Investment Management, Inc., has been designated as one of our directors by KAFU Holdings, L.P. Mr. Sinnott disclaims any deemed beneficial ownership of any units held by KAFU Holdings, L.P. or its affiliates, other than through his 4.5% limited partner interest in KAFU Holdings, L.P. The address for KAFU Holdings, L.P. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.

(2)
Mr. Allen is the sole stockholder and Chairman of the Board of Vulcan Energy II Inc., which is the record holder of 1,298,280 class C common units. The address of Mr. Allen and Vulcan Energy II Inc. is 505 Fifth Avenue S, Suite 900, Seattle, Washington 98104. In addition, Mr. Allen owns approximately 88.38% of the outstanding shares of common stock of Vulcan Energy Corporation. Vulcan Energy Corporation is the sole stockholder of Plains Resources Inc. Plains Resources Inc. indirectly owns 11,084,039 of our common units and 1,307,190 of our Class B common units, representing 18.4% of our total limited partner units. A subsidiary of Plains Resources Inc. owns 44% of the equity of our general partner. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Plains Resources or any of its affiliates. See "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters."

        Any prospectus supplement reflecting a sale of common units hereunder will set forth, with respect to the selling unitholders:

        All expenses incurred with the registration of the common units owned by the selling unitholders will be borne by us.

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PLAN OF DISTRIBUTION

        We are registering the common units on behalf of the selling unitholders. As used in this prospectus, "selling unitholders" includes donees and pledgees selling common units received from a named selling unitholder after the date of this prospectus.

        Under this prospectus, the selling unitholders intend to offer our securities to the public:

        The selling unitholders may price the common units offered from time to time:

        We will pay the costs and expenses of the registration and offering of the common units offered hereby. We will not pay any underwriting fees, discounts and selling commissions allocable to each selling unitholder's sale of its respective common units, which will be paid by the selling unitholders. Broker-dealers may act as agent or may purchase securities as principal and thereafter resell the securities from time to time:

        Broker-dealers or underwriters may receive compensation in the form of underwriting discounts or commissions and may receive commissions from purchasers of the securities for whom they may act as agents. If any broker-dealer purchases the securities as principal, it may effect resales of the securities from time to time to or through other broker-dealers, and other broker-dealers may receive compensation in the form of concessions or commissions from the purchasers of securities for whom they may act as agents.

        To the extent required, the names of the specific managing underwriter or underwriters, if any, as well as other important information, will be set forth in prospectus supplements. In that event, the discounts and commissions the selling unitholders will allow or pay to the underwriters, if any, and the discounts and commissions the underwriters may allow or pay to dealers or agents, if any, will be set forth in, or may be calculated from, the prospectus supplements. Any underwriters, brokers, dealers and agents who participate in any sale of the securities may also engage in transactions with, or perform services for, us or our affiliates in the ordinary course of their businesses.

        In addition, the selling unitholders have advised us that they may sell common units in compliance with Rule 144, if available, or pursuant to other available exemptions from the registration requirements under the Securities Act, rather than pursuant to this prospectus.

        To the extent required, this prospectus may be amended or supplemented from time to time to describe a specific plan of distribution.

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        In connection with offerings under this shelf registration and in compliance with applicable law, underwriters, brokers or dealers may engage in transactions which stabilize or maintain the market price of the securities at levels above those which might otherwise prevail in the open market. Specifically, underwriters, brokers or dealers may over-allot in connection with offerings, creating a short position in the securities for their own accounts. For the purpose of covering a syndicate short position or stabilizing the price of the securities, the underwriters, brokers or dealers may place bids for the securities or effect purchases of the securities in the open market. Finally, the underwriters may impose a penalty whereby selling concessions allowed to syndicate members or other brokers or dealers for distribution the securities in offerings may be reclaimed by the syndicate if the syndicate repurchases previously distributed securities in transactions to cover short positions, in stabilization transactions or otherwise. These activities may stabilize, maintain or otherwise affect the market price of the securities, which may be higher than the price that might otherwise prevail in the open market, and, if commenced, may be discontinued at any time.


VALIDITY OF THE COMMON UNITS

        The validity of the common units will be passed upon for Plains All American Pipeline by Vinson & Elkins L.L.P., Houston, Texas. The selling unitholders' counsel and the underwriters' own legal counsel will advise them about other issues relating to any offering in which they participate.

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EXPERTS

        The consolidated financial statements of Plains All American Pipeline, L.P. as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003 and the balance sheet of Plains AAP, L.P. as of December 31, 2003 included in this Prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

        The combined financial statements of the Capline Pipe Line Business, Capwood Pipe Line Business and Patoka Pipe Line Business (the "Businesses") as of December 31, 2003 and 2002 and for the year ended December 31, 2003 and for the periods from February 14, 2002 through December 31, 2002 and January 1, 2002 through February 13, 2002 included in this Prospectus have been so included in reliance on the report (which report contains an explanatory paragraph relating to the Businesses being sold to Plains All American Pipeline, L.P. as described in Note 6 to the combined financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

        The consolidated financial statements of Link Energy LLC and its subsidiaries (Successor Company) at December 31, 2003 and for the period from March 1, 2003 to December 31, 2003 and of EOTT Energy Partners, L.P. and its subsidiaries (Predecessor Company) at December 31, 2002 and for the period from January 1, 2003 to February 28, 2003 and for each of the two years in the period ended December 31, 2002 included in this Prospectus have been so included in reliance on the reports (which contain an explanatory paragraph relating to the Successor Company's and Predecessor Company's ability to continue as a going concern as described in Note 3 to the consolidated financial statements, an explanatory paragraph relating to the adoption of fresh start accounting as described in Note 1 to the consolidated financial statements and an explanatory paragraph relating to the restatement of the financial results as described in Notes 1 and 10 to the consolidated financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.


WHERE YOU CAN FIND MORE INFORMATION

        We file annual, quarterly and special reports and other information with the Securities and Exchange Commission under the Securities Exchange Act of 1934. You can inspect and/or copy these reports and other information at offices maintained by the SEC, including:

        In addition, please call the SEC at 1-800-732-0330 for further information on their public reference room.

        Further, our common units are listed on the New York Stock Exchange, and you can inspect similar information at the offices of the New York Stock Exchange, located at 20 Broad Street, New York, New York 10005.

        You can read and copy any of our materials filed with the SEC at our website at http://www.paalp.com or you may request a copy of these filings at no cost by making written or telephone requests for copies to:

        You should rely only on the information provided in this prospectus. The information contained on our website is not a part of this prospectus. We have not authorized anyone else to provide you with any information. You should not assume that the information provided in this prospectus is accurate as of any date other than the date on the cover of this prospectus.

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FORWARD-LOOKING STATEMENTS

        All statements, other than statements of historical fact, included in this prospectus are forward-looking statements, including, but not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," "intend" and "forecast," and similar expressions and statements regarding our business strategy, plans and objectives for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. Certain factors could cause actual results to differ materially from results anticipated in the forward-looking statements. These factors include, but are not limited to:

        Other factors described herein, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read "Risk Factors" beginning on page 2 of this prospectus. Except as required by securities laws, we do not intend to update these forward-looking statements and information.

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INDEX TO FINANCIAL STATEMENTS

 
PLAINS ALL AMERICAN PIPELINE, L.P.
  UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS:
    Introduction
    Unaudited Pro Forma Combined Statement of Operations for the six months ended June 30, 2004
    Unaudited Pro Forma Combined Statement of Operations for the twelve months ended December 31, 2003
    Notes to Unaudited Pro Forma Combined Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
  UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:
    Unaudited Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003
    Unaudited Consolidated Statements of Operations for the six months ended June 30, 2004 and 2003
    Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2004 and 2003
    Unaudited Consolidated Statement of Partners' Capital for the six months ended June 30, 2004
    Unaudited Consolidated Statements of Comprehensive Income for the six months ended June 30, 2004 and 2003
    Unaudited Consolidated Statement of Changes in Accumulated Other Comprehensive Income for the six months ended June 30, 2004
    Unaudited Notes to the Consolidated Financial Statements

PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
  CONSOLIDATED FINANCIAL STATEMENTS:
    Report of Independent Registered Public Accounting Firm
    Consolidated Balance Sheets as of December 31, 2003 and 2002
    Consolidated Statements of Operations for the years ended December 31, 2003, 2002 and 2001
    Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001
    Consolidated Statement of Changes in Partners' Capital for the years ended December 31, 2003, 2002 and 2001
    Consolidated Statements of Comprehensive Income for the years ended December 31, 2003, 2002 and 2001
    Consolidated Statement of Changes in Accumulated Other Comprehensive Income (loss) for the years ended December 31, 2003, 2002 and 2001
    Notes to Consolidated Financial Statements
 

F-1



LINK ENERGY LLC
  UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:
    Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2004 (Successor Company), one month ended March 31, 2003 (Successor Company) (Restated), and two months ended February 28, 2003 (Predecessor Company) (Restated)
    Unaudited Condensed Consolidated Balance Sheets as of March 31, 2004 and December 31, 2003 (Successor Company)
    Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2004 (Successor Company), one month ended March 31, 2003 (Successor Company) (Restated), and two months ended February 28, 2003 (Predecessor Company) (Restated)
    Unaudited Condensed Consolidated Statement of Members' Capital for the three months ended March 31, 2004 (Successor Company)
    Notes to Unaudited Condensed Consolidated Financial Statements

LINK ENERGY LLC
  CONSOLIDATED FINANCIAL STATEMENTS:
    Report of Independent Registered Public Accounting Firm (Successor Company)