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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.D.C. 20549

FORM 10-K/A
AMENDMENT NO. 1Form 10-K


ý
(Mark One)
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20032006

OR

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-14569

Commission file number 1-14569
PLAINS ALL AMERICAN PIPELINE, L.P.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

76-0582150
(I.R.S. Employer Identification No.)

Delaware

76-0582150
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)
333 Clay Street, Suite 1600,
Houston, Texas 77002
(Address of principal executive offices)
(Zip (Zip Code)

(713) 646-4100
(Registrant'sRegistrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class
Each Class
Name of each exchangeEach Exchange on which registered
Which Registered
Common Units New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ

     No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ýþ     No o

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the best of registrant'sregistrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to thisForm 10-K.  þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” inRule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer  þ     Accelerated Filer  o     Non-Accelerated Filer  o

Indicate by check mark if the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act).  Yes o     No þ
The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and holders of 10% or more of the Common Units outstanding, for this purpose, as if they may be affiliates of the registrant) was approximately $1.1$2.7 billion on June 30, 2003,2006, based on $31.48$43.67 per unit, the closing price of the Common Units as reported on the New York Stock Exchange on such date.

At February 17, 2004,20, 2007, there were outstanding 57,162,638109,405,178 Common Units and 1,307,190 Class B Common Units.

DOCUMENTS INCORPORATED BY REFERENCE:    NoneREFERENCE
NONE


PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FORM 10-K/A—200310-K — 2006 ANNUAL REPORT

Introductory Note

        Plains All American Pipeline, L.P. is filing this Amendment No. 1 on Form 10-K/A ("Amendment No. 1") to reflect certain revisions to disclosures previously included in its Annual Report on Form 10-K for the fiscal year ended December 31, 2003, which was originally filed on March 1, 2004 (the "Original Filing"). The revisions to the Original Filing relate to a recently completed reviewTable of the Original Filing by the Securities and Exchange Commission's Division of Corporation Finance.

        The following Items of the Original Filing are amended by this Amendment No. 1:

Contents
Page
Part I
Items 1 and 2.
 Business and Properties1

Item 1A.
Risk Factors40
Item 1B.
Unresolved Staff Comments54
Item 3.
Legal Proceedings54
Item 4.
Submission of Matters to a Vote of Security Holders56
Part II
Item 5.
Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities56
Item 6.


Selected Financial and Operating Data58

Item 7.


Management's		Management’s Discussion and Analysis of Financial Condition and Results of Operations60

Item 7A.


Quantitative and Qualitative Disclosures About Market RisksRisk90

Item 8.


Financial Statements and Supplementary Data

Item 10.

Directors and Executive Officers of our General Partner

Item 13.

Certain Relationships and Related Transactions

Item 15.

Exhibits, Financial Statement Schedules and Reports on Form 8-K

        Please note that the information contained in this Form 10-K/A, including the financial statements and notes thereto, do not reflect events occurring after the date of the Original Filing, except as reflected in "Note 16—Subsequent Events (Unaudited)" in the "Notes to the Consolidated Financial Statements." For a description of these events, please read Plains All American Pipeline, L.P.'s reports filed under the Exchange Act of 1934, as amended, since March 1, 2004.


PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
FORM 10-K/A—2003 ANNUAL REPORT

Table of Contents



Page
Part I

Items 1 and 2.

Business and Properties

1
Item 3. Legal Proceedings92
Item 9.
 37
Item 4.Submission of Matters to a Vote of Security Holders37

Part II

Item 5.

Market for the Registrant's Common Units and Related Unitholder Matters

38
Item 6.Selected Financial and Operating Data39
Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations42
Item 7A.Quantitative and Qualitative Disclosures About Market Risks74
Item 8.Financial Statements and Supplementary Data76
Item 9.Changes in and Disagreements withWith Accountants on Accounting and Financial Disclosure 7792
Item 9A.
 Controls and Procedures 7792

Item 9B.
Other Information93
Part III

Item 10.


Directors and Executive Officers of Our General Partner

78
Item 11. and Corporate Governance Executive Compensation93
Item 11.
 85
Item 12.Executive Compensation 103
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholders'Unitholder Matters 90117
Item 13.
 Certain Relationships and Related Transactions, and Director Independence 94121
Item 14.
 Principal Accountant Fees and Services 98126

Part IV

Item 15.


Exhibits and Financial Statement Schedules and Reports on Form 8-K
 
99		127
Certificate of Incorporation
Bylaws
Second Supplemental Indenture
Directors' Compensation Summary
Fourth Amendment to Credit Agreement
Long-Term Incentive Plan
List of Subsidiaries
Consent of PricewaterhouseCoopers LLP
Certification of PEO Pursuant to Rules 13a-14(a)
Certification of PFO Pursuant to Rules 13a-14(a)
Certification of PEO Pursuant to Section 1350
Certification of PFO Pursuant to Section 1350


FORWARD-LOOKING STATEMENTS

All statements included in this report, other than statements of historical fact, included in this report are forward-looking statements, including but not limited to statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," "intend"“anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and "forecast,"“forecast,” and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. The absence of these words, however, does not mean that the statements are not forward-looking. 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:

    •
    abrupt or severe production declines or production interruptions in outer continental shelf production located offshore California and transported on our pipeline system;

    •
    declines in volumes shipped on the Basin Pipeline and our other pipelines by third party shippers;

    •
    the availability of adequate third-party production volumes for transportation and marketing in the areas in which we operate;

    •
    demand for various grades of crude oil and resulting changes in pricing conditions or transmission throughput requirements;

    •
    fluctuations in refinery capacity in areas supplied by our transmission lines;

    •
    the effects of competition;

    •
    the success of our risk management activities;

    •
    the impact of crude oil price fluctuations;

    •
    the availability of, and ability to consummate, acquisition or combination opportunities;

    •
    successful integration and future performance of acquired assets;

    •
    continued creditworthiness of, and performance by, counterparties;

    •
    successful third-party drilling efforts in areas in which we operate pipelines or gather crude oil;

    •
    our levels of indebtedness and our ability to receive credit on satisfactory terms;

    •
    shortages or cost increases of power supplies, materials or labor;

    •
    weather interference with business operations or project construction;

    •
    the impact of current and future laws and governmental regulations;

    •
    the currency exchange rate of the Canadian dollar;

    •
    environmental liabilities that are not covered by an indemnity, insurance or existing reserves;

    •
    fluctuations in the debt and equity markets including the price of our units at the time of vesting under our Long-Term Incentive Plan; and

    •
    general economic, market or business conditions.

• our failure to successfully integrate the business operations of Pacific Energy Partners L.P. (“Pacific”) or our failure to successfully integrate any future acquisitions;
• the failure to realize the anticipated cost savings, synergies and other benefits of the merger with Pacific;
• the success of our risk management activities;
• environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
• maintenance of our credit rating and ability to receive open credit from our suppliers and trade counterparties;
• abrupt or severe declines or interruptions in outer continental shelf production located offshore California and transported on our pipeline systems;
• failure to implement or capitalize on planned internal growth projects;
• the availability of adequate third party production volumes for transportation and marketing in the areas in which we operate, and other factors that could cause declines in volumes shipped on our pipelines by us and third party shippers;
• fluctuations in refinery capacity in areas supplied by our mainlines, and other factors affecting demand for various grades of crude oil, refined products and natural gas and resulting changes in pricing conditions or transmission throughput requirements;
• the availability of, and our ability to consummate, acquisition or combination opportunities;
• our access to capital to fund additional acquisitions and our ability to obtain debt or equity financing on satisfactory terms;
• future performance of acquired assets or businesses and the risks associated with operating in lines of business that are distinct and separate from our historical operations;
• unanticipated changes in crude oil market structure and volatility (or lack thereof);
• the impact of current and future laws, rulings and governmental regulations;
• the effects of competition;
• continued creditworthiness of, and performance by, our counterparties;
• interruptions in service and fluctuations in tariffs or volumes onthird-party pipelines;
• increased costs or lack of availability of insurance;
• fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our Long-Term Incentive Plans;
• the currency exchange rate of the Canadian dollar;
• shortages or cost increases of power supplies, materials or labor;
• weather interference with business operations or project construction;
• risks related to the development and operation of natural gas storage facilities;
• general economic, market or business conditions; and
• other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, refined products and liquefied petroleum gas and other natural gas related petroleum products.
Other factors described herein,elsewhere in this document, or factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please read "Risk Factors“Risks Related to Our Business"Business” discussed in Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations."1A. “Risk Factors.” Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.


PART I

Items 1 and 2.  Business and Properties

General

        We are

Plains All American Pipeline, L.P. is a publicly traded Delaware limited partnership (the "Partnership"), formed in 1998September 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in thisForm 10-K, the terms “Partnership,” “Plains,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries, unless the context indicates otherwise.
We are engaged in interstatethe transportation, storage, terminalling and intrastatemarketing of crude oil, transportation,refined products and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas-related petroleum products. We refer to liquefied petroleum gas and other natural gas related petroleum products primarilycollectively as “LPG.” Through our 50% equity ownership in Texas, California, Oklahoma, Louisiana and the Canadian Provinces of Alberta and Saskatchewan. Our operations can be categorized into two primary business activities:

    •
    Crude Oil Pipeline Transportation Operations.  We ownPAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”), we develop and operate approximately 7,000 milesnatural gas storage facilities.
Prior to the fourth quarter of gathering2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business (most notably in conjunction with the Pacific acquisition), we have revised the manner in which we internally evaluate our segment performance and mainlinedecide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing.
Transportation — Our transportation segment operations generally consist of fee-based activities associated with transporting volumes of crude oil and refined products on pipelines locatedand gathering systems. We generate revenue through a combination of tariffs,third-party leases of pipeline capacity, transportation fees, barrel exchanges and buy/sell arrangements.
As of December 31, 2006, we employed a variety of owned or leased long-term physical assets throughout the United States and Canada.Canada in this segment, including approximately:
• 20,000 miles of active pipelines and gathering systems;
• 30 million barrels of tank capacity used primarily to facilitate pipeline throughput; and
• 57 transport and storage barges and 30 transport tugs through our 50% interest in Settoon Towing, LLC (“Settoon Towing”).
We also include in this segment our equity earnings from our investments in the Butte Pipe Line Company (“Butte”) and Frontier Pipeline Company (“Frontier”) pipeline systems, in which we own minority interests, and Settoon Towing, in which we own a 50% interest.
Facilities — Our activities from pipelinefacilities segment operations generally consist of transportingfee-based activities associated with providing storage, terminalling and throughput services for crude oil, forrefined products and LPG, as well as LPG fractionation and isomerization services. We generate revenue through a fee, third partycombination ofmonth-to-month and multi-year leases and processing arrangements.
As of pipeline capacity, barrel exchangesDecember 31, 2006, we owned and buy/sell arrangements.

•
Gathering, Marketing, Terminallingemployed a variety of long-term physical assets throughout the United States and Storage Operations.  We own and operateCanada in this segment, including:
• approximately 30 million barrels of active, above-ground terminalling and storage facilities;
• approximately 1.3 million barrels of active, underground terminalling and storage facilities; and
• a fractionation plant in Canada with a processing capacity of 4,400 barrels per day, and a fractionation and isomerization facility in California with an aggregate processing capacity of 22,000 barrels per day.
At year-end 2006, we were in the process of constructing approximately 24.012.5 million barrels of additional above-ground crude oil terminalling and storage facilities, including tankage associated with our pipeline systems. These facilities include a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing,the majority of which we referexpect to place in this report asservice during 2007.
Our facilities segment also includes our equity earnings from our investment in PAA/Vulcan. At December 31, 2006, PAA/Vulcan owned and operated approximately 25.7 billion cubic feet of underground storage capacity and


1

is constructing an additional 24 billion cubic feet of underground storage capacity, which is expected to be placed in service in stages over the Cushing Interchange, is onenext three years.
Marketing — Our marketing segment operations generally consist of the largestfollowing merchant activities:
• the purchase of U.S. and Canadian crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities, as well as the purchase of foreign cargoes at their load port and various other locations in transit;
• the storage of inventory during contango market conditions;
• the purchase of refined products and LPG from producers, refiners and other marketers;
• the resale or exchange of crude oil, refined products and LPG at various points along the distribution chain to refiners or other resellers to maximize profits; and
• arranging for the transportation of crude oil, refined products and LPG on trucks, barges, railcars, pipelines and ocean-going vessels to our terminals and third-party terminals.
Our marketing activities are designed to produce a stable baseline of results in a variety of market hubsconditions, while at the same time providing upside exposure to opportunities inherent in the United Statesvolatile market conditions. These activities utilize storage facilities at major interchange and the designated delivery point for NYMEX crude oil futures contracts. We utilize our storage tanks to counter-cyclically balance our gatheringterminalling locations and marketing operations and to execute various hedging strategies to stabilize profits and reduce the negative impact of market volatility and provide counter-cyclical balance.
Except for pre-defined inventory positions, our policy is generally to purchase only product for which we have a market, to structure our sales contracts so that price fluctuations do not materially affect the segment profit we receive, and not to acquire and hold physical inventory, futures contracts or other derivative products for the purpose of speculating on commodity price changes.
In addition to substantial working inventories and working capital associated with its merchant activities, the marketing segment also employs significant volumes of crude oil and LPG as linefill or minimum inventory requirements under service arrangements with transportation carriers and terminalling providers. The marketing segment also employs trucks, trailers, barges, railcars and leased storage.
As of December 31, 2006, the marketing segment owned crude oil and LPG classified as long-term assets and a variety of owned or leased long-term physical assets throughout the United States and Canada, including approximately:
• 7.9 million barrels of crude oil and LPG linefill in pipelines owned by the Partnership;
• 1.5 million barrels of crude oil and LPG linefill in pipelines owned by third parties;
• 500 trucks and 600 trailers; and
• 1,300 railcars.
In connection with its operations, the marketing segment secures transportation and facilities services from the Partnership’s other two segments as well as third-party service providers undermonth-to-month and multi-year arrangements. Inter-segment transportation service rates are based on posted tariffs for pipeline transportation services. Facilities segment services are also obtained at rates consistent with rates charged to third parties for similar services; however, certain terminalling and storage rates are discounted to our marketing segment to reflect the fact that these services may be canceled on short notice to enable the facilities segment to provide services to third parties.
Counter-Cyclical Balance
Access to storage tankage by our marketing segment provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow associated with this segment. The strategic use of our terminalling and storage assets in conjunction with our marketing operations generally provides us with the flexibility to maintain a base level of margin irrespective of crude oil market volatility.conditions and, in certain circumstances, to realize incremental


2

margin during volatile market conditions. See "—“— Crude Oil Volatility; Counter-Cyclical Balance; Risk Management." Our terminalling and storage operations also generate revenue at the Cushing Interchange and our other locations through a combination of storage and throughput charges to third parties. Our gathering and marketing operations include:

•
the purchase of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities;

•
the transportation of crude oil on trucks, barges and pipelines;

•
the subsequent resale or exchange of crude oil at various points along the crude oil distribution chain; and

•
the purchase of liquified petroleum gas and other petroleum products (collectively "LPG") from producers, refiners and other marketers, and the sale of LPG to wholesalers, retailers and industrial end users.

Management.”

Business Strategy

Our principal business strategy is to capitalize onprovide competitive and efficient midstream transportation, terminalling, storage and marketing services to our producer, refiner and other customers, and to address the regional crude oil supply and demand imbalances for crude oil, refined products and LPG that exist in the United States and Canada by combining the strategic location and distinctive capabilities of our transportation, terminalling and terminallingstorage assets with our extensive marketing and distribution expertiseexpertise. We believe successful execution of this strategy will enable us to generate sustainable earnings and cash flow.

We intend to executegrow our business strategy by:

    •
    increasing
• optimizing our existing assets and realizing cost efficiencies through operational improvements;
• developing and implementing internal growth projects that (i) address evolving crude oil, refined product and LPG needs in the midstream transportation and infrastructure sector and (ii) are well positioned to benefit from long-term industry trends and opportunities;
• utilizing our assets along the Gulf, West and East Coasts along with our Cushing Terminal and leased assets to increase our presence in the waterborne importation of foreign crude oil;
• establishing a presence in the refined product supply and marketing sector;
• selectively pursuing strategic and accretive acquisitions of crude oil, refined product and LPG transportation, terminalling, storage and marketing assets that complement our existing asset base and distribution capabilities; and
• using our terminalling and storage assets in conjunction with our marketing activities to address physical market imbalances, mitigate inherent risks and increase margin.
PAA/Vulcan’s natural gas storage assets are also well-positioned to benefit from long-term industry trends and optimizing throughput on our existing pipelineopportunities. Our natural gas storage growth strategies are to develop and gathering assets and realizing cost efficiencies through operational improvements;

•
utilizing and expanding our Cushing Terminal and our other assets to service the needs of refinersimplement internal growth projects and to profit from merchant activities that take advantage of crude oil pricing and quality differentials;

      •
      selectively pursuingpursue strategic and accretive acquisitions of crude oil transportation assets, including pipelines, gathering systems, terminallingnatural gas storage projects and storage facilitiesfacilities. We also intend to prudently and economically leverage our asset base, knowledge base and skill sets to participate in other assetsenergy-related businesses that have characteristics and opportunities similar to, or that otherwise complement, our existing asset base and distribution capabilities; and

      •
      optimizing and expanding our Canadian operations and our presence in the Gulf Coast and Gulf of Mexico to take advantage of anticipated increases in the volume and qualities of crude oil produced in these areas.

            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.

    activities.

    Financial Strategy

    Targeted Credit Profile
    We believe that a major factor in our continued success will beis 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 intentionWe intend 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:

      •
    • an average long-termdebt-to-total capitalization ratio of approximately 50%;
    • an average long-termdebt-to-EBITDA multiple of approximately 3.5x or less (EBITDA is earnings before interest, taxes, depreciation and amortization); and
    • an averageEBITDA-to-interest coverage multiple of approximately 3.3x or better.
    The first two of these three metrics include long-term debt-to-total capitalization ratiodebt as a critical measure. In certain market conditions, we also incur short-term debt in connection with marketing activities that involve the simultaneous purchase and forward sale of approximately 60% or less;

    •
    an averagecrude oil. The crude oil purchased in these transactions is hedged, is required to be stored on amonth-to-month basis and is sold to high-credit quality counterparties. We do not consider the working capital borrowings associated with this activity to be part of our long-term debt-to-EBITDA ratiocapital structure. These borrowings are self-liquidating as they are repaid with sales proceeds following delivery of approximately 3.5x or less (EBITDA is earnings before interest, taxes, depreciationthe crude oil. We also anticipate performing similar activities for refined products as we expand our presence in the refined products supply and amortization); andmarketing sector.



    •
    an average EBITDA-to-interest coverage ratio of approximately 3.3x or better.
    3

            As of December 31, 2003, we were within our targeted credit profile.

    In order for us to maintain our targeted credit profile and achieve growth through internal growth projects and acquisitions, we intend to fund acquisitions using approximately equal proportionsat least 50% of the capital requirements associated with these activities with equity and debt. In certain cases, acquisitions will initially be financed using debt since it is difficult to predict the actual timingcash flow in excess of accessing the market to raise equity. Accordingly, fromdistributions. From time to time, we may be temporarily outside the parameters of our targeted credit profile.

    profile as, in certain cases, these capital expenditures and acquisitions may be financed initially using debt or there may be delays in realizing anticipated synergies from acquisitions or contributions to adjusted EBITDA from capital expansion projects. In this instance, “adjusted EBITDA” means earnings before interest, tax, depreciation, amortization, Long-Term Incentive Plan charges and gains and losses attributable to Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”). At December 2003, Moody's Investors Service raised31, 2006, we were above our targeted parameter for the long-termdebt-to-EBITDA ratio (due primarily to the closing of the Pacific acquisition in November 2006) and within the parameters of the other credit metrics. Based on our December 31, 2006 long-term debt balance and the midpoint of our adjusted EBITDA guidance for 2007 furnished in aForm 8-K dated February 22, 2007, our long-termdebt-to-adjusted-EBITDA multiple would be 3.8.

    Credit Rating
    As of February 2007, our senior unsecured rating to Ba1, affirmed our senior implied credit rating of Ba1 and placed us on review for a possible ratings upgrade. In November 2003,with Standard & Poor's raisedPoor’s and Moody’s Investment Services were BBB- negative outlook and Baa3 stable outlook, respectively, both of which are considered “investment grade.” We have targeted the attainment of even stronger investment grade ratings of mid to high-BBB and Baa categories for Standard & Poor’s and Moody’s Investment Services, respectively. We cannot give assurance that our senior unsecured ratingcurrent ratings will remain in effect for any given period of time, that we will be able to BBB- (the same rating as our senior implied rating) from BB+. You should noteattain the higher ratings we have targeted or that one or both of these ratings will not be lowered or withdrawn entirely by the ratings agency. Note that a credit rating is not a recommendation to buy, sell or hold securities, and may be subject to revisionrevised or withdrawalwithdrawn at any time.

    Competitive Strengths

    We believe that the following competitive strengths position us successfully to successfully execute our principal business strategy:
    • Many of our transportation segment and facilities segment assets are strategically located and operationally flexible and have additional capacity or expansion capability.  The majority of our primary transportation segment assets are in crude oil service, are located in well-established oil producing regions and transportation corridors, and are connected, directly or indirectly, with our facilities segment assets located at major trading locations and premium markets that serve as gateways to major North American refinery and distribution markets where we have strong business relationships.
    • We possess specialized crude oil market knowledge.  We believe our business relationships with participants in various phases of the crude oil distribution chain, from crude oil producers to refiners, as well as our own industry expertise, provide us with an extensive understanding of the North American physical crude oil markets.
    • Our business activities are counter-cyclically balanced.  We believe the balance of activities provided by our marketing segment provides us with a counter-cyclical balance that generally affords us the flexibility (i) to maintain a base level of margin irrespective of crude oil market conditions and (ii), in certain circumstances, to realize incremental margin during volatile market conditions.
    • We have the evaluation, integration and engineering skill sets and the financial flexibility to continue to pursue acquisition and expansion opportunities.  Over the past nine years, we have completed and integrated approximately 45 acquisitions with an aggregate purchase price of approximately $5.1 billion ($2.6 billion excluding the Pacific acquisition, for which we are still in the process of integrating). We have also implemented internal expansion capital projects totaling over $700 million. In addition, we believe we have significant resources to finance future strategic expansion and acquisition opportunities. As of December 31, 2006, we had approximately $1.3 billion available under our committed credit facilities, subject to continued covenant compliance. We believe we have one of the strongest capital structures relative to other master limited partnerships with capitalizations greater than $1.0 billion. In addition, the investors in our general partner are diverse and financially strong and have demonstrated their support by providing


    4


    capital to help finance previous acquisitions and expansion activities. We believe they are supportive long-term sponsors of the partnership.
        •
        Our Cushing Terminal is strategically located, operationally flexible and readily expandable.   Our Cushing Terminal interconnects with the Cushing Interchange's major inbound and outbound pipelines, providing access to both foreign and domestic crude oil. Our Cushing Terminal is the most modern large-scale terminalling and storage facility at the Cushing Interchange, incorporating (i) operational enhancements designed to safely and efficiently terminal, store, blend and segregate large volumes and multiple varieties of crude oil and (ii) extensive environmental safeguards. Since completing the initial construction of the Cushing Terminal in 1994, we have completed three expansion phases of approximately 1.1 million barrels each, thus expanding the facility to its current capacity of 5.3 million barrels. In January 2004, we announced the commencement of our Phase IV expansion project, which will increase capacity by an incremental 1.1 million barrels, or approximately 20% of current capacity.
        • We have an experienced management team whose interests are aligned with those of our unitholders.  Our executive management team has an average of more than 20 years industry experience, with an average of more than 15 years with us or our predecessors and affiliates. Certain members of our senior management team own an approximate 5% interest in our general partner and collectively own approximately 850,000 common units, including fully vested options. In addition, through grants of phantom units, the senior management team also owns significant contingent equity incentives that generally vest upon achievement of performance objectives, continued service or both. These interests give management a vested interest in our continued success.
        We believe that the facility can be further expandedmany of these competitive strengths have similar application to meet additional demand should market conditions warrant. In addition, we own approximately 18.7 million barrels of above-ground crude oil terminalling and storage assets elsewhereour efforts to expand our presence in the United Statesrefined products, LPG and Canada that complement our Cushing Terminal and enable us to serve the needs of our customers.

        •
        We possess specialized crude oil market knowledge.  We believe our business relationships with participants in all phases of the crude oil distribution chain, from crude oil producers to refiners, as well as our own industry expertise, provide us with an extensive understanding of the North American physical crude oil markets.

        •
        The combination of our business activities provide a counter-cyclical balance.  We believe the manner in which we integrate the activities of our gathering and marketing operations with our terminalling andnatural gas storage operations provides a counter-cyclical balance to our business, irrespective of the structure of the crude oil market. In combination with our pipeline transportation operations, we believe these activities have a stabilizing effect on our cash flow from operations.

        •
        sectors.
      We have the financial flexibility to continue to pursue expansion and acquisition opportunities.  We believe we have significant resources to finance strategic expansion and acquisition opportunities, including our ability to issue additional partnership units, borrow under our credit facilities and issue additional notes in the long-term debt capital markets. We have committed senior unsecured facilities totaling $750 million. Under our committed facilities, each bank has committed to lend to us its pro rata share of the total facility amount. These credit facilities are available for working capital purposes and to fund capital expenditures, including acquisitions. At December 31, 2003, we had approximately $596.8 million of unused capacity under these credit facilities. We also have a $200 million uncommitted facility to finance the purchase of hedged crude oil inventory. Under our uncommitted facility, the banks have made no binding commitment to lend; rather, the banks can exercise discretion with respect to each borrowing request. Once they have agreed to lend, however, the amounts associated with any particular borrowing becomes "committed" in that the banks have no discretion to demand prepayment. The uncommitted facility is secured by the purchased inventory and related receivables. At December 31, 2003, we have approximately $100 million outstanding under our hedged crude oil inventory facility resulting in unused uncommitted capacity of approximately $100 million under this facility. Our usage is subject to covenant compliance. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

      •
      We have an experienced management team whose interests are aligned with those of our stakeholders.  Our executive management team has an average of more than 20 years industry experience, with an average of over 15 years with us or our predecessors and affiliates. Members of our senior management team own a 4% interest in our general partner, approximately 400,000 common units and, through phantom unit grants and options, own contingent equity incentives that vest

          primarily upon achievement of specified performance objectives. A significant portion of the awards under our Long-Term Incentive Plan ("LTIP") have vested or will vest in the first half of 2004.

      Organizational History

      We were formed as a master limited partnership in September 1998 to acquire and operate the midstream crude oil businessbusinesses and assets of Plains Resources Inc. and its wholly-owned subsidiaries ("Plains Resources") as a separate, publicly traded master limited partnership.predecessor entity. We completed our initial public offering in November 1998. As a result of subsequent equity offerings and the purchase inSince June 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 22% as of February 17, 2004. See Item 12. "Security Ownership of Certain Beneficial Owners and Management and Related Unitholders' Matters."

              As a result of the 2001 transaction, our 2% general partner interest ishas been 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’s general partner. Unless the context otherwise requires, we use the term "general partner"“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 7 owners with the largest interest, 44%, held by Plains Resources. We use the phrase "former general partner" to refer to the subsidiaryseven owners. See Item 12. “Security Ownership of Plains Resources that formerly held the general partner interest.

      Certain Beneficial Owners and Management and Related Unitholder Matters — Beneficial Ownership of General Partner Interest.”

      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,Our general partner, Plains Marketing,AAP, L.P. and Plains Pipeline, L.P. Our Canadian operations are conducted through Plains Marketing Canada, L.P. We currently have fewer than 20 subsidiaries, although we may form new subsidiaries from time to time in connection with acquisitions.

      , is managed by its general partner, Plains All American GP LLC, manageswhich has ultimate responsibility for conducting our operationsbusiness and activitiesmanaging our operations. See Item 10. “Directors and employsExecutive Officers of our officersGeneral Partner and personnel, who devote 100% of their efforts to the management of the Partnership.Corporate Governance.” Our general partner does not receive a management fee or other compensation in connection with its management of our business, but it is reimbursed for substantially all direct and indirect expenses incurred on our behalf. Canadian personnel are employed by Plains Marketing Canada L.P.'s general partner, PMC (Nova Scotia) Company.

              Our general partner owns all of the incentive distribution rights. These rights provide that our general partner receives an increasing percentage of cash distributions (in addition to its 2% general partner interest) as distributions reach and exceed certain threshold levels. See Item 5. "Market for the Registrant's Common Units and Related Unitholder Matters—Cash Distribution Policy."



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


      5

      Partnership the operating partnershipsStructure
      (1) Based on Form 4 filings for executive officers and directors, 13D filings for Paul G. Allen and Richard Kayne and other information believed to be reliable for the remaining investors, this group, or affiliates of such investors, owns approximately 26 million limited partner units, representing approximately 23.5% of the limited partner interest.
      Acquisitions
      The acquisition of assets and the subsidiaries.


      Acquisitionsbusinesses that are strategic and Dispositions

              Ancomplementary to our existing operations constitutes an integral component of our business strategy and growth objective is to acquireobjective. Such assets and operationsbusinesses include crude oil related assets, refined products assets and LPG assets, as well as other energy transportation related assets that are strategichave characteristics and complementaryopportunities similar to these business lines and enable us to leverage our existing operations.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. SinceBetween 1998 and December 31, 2006, we have completed numerousapproximately 45 acquisitions for an aggregatea cumulative purchase price of approximately $1.3$5.1 billion. In addition, from time to time


      6

      The following table summarizes acquisitions greater than $50 million that we have sold assets that are no longer considered essential to our operations.

              During 2003,completed over the past five years:

               
            Approximate
      		 
      Acquisition
      		 
      Date
      		 
      Description
      		 Purchase Price 
            (In millions) 
       
      Pacific Energy Partners LP November 2006 Merger of Pacific Energy Partners with and into the Partnership $2,456 
      Products Pipeline System September 2006 Three refined products pipeline systems $66 
      Crude Oil Systems July 2006 64.35% interest in theClovelly-to-Meraux Pipeline system; 100% interest in the BayMarchand-to-Ostrica-to-Alliance system and various interests in the High Island Pipeline System (2) $130 
      Andrews Petroleum and Lone Star Trucking April 2006 Isomerization, fractionation, marketing and transportation services $220 
      South Louisiana Gathering and Transportation Assets (SemCrude) April 2006 Crude oil gathering and transportation assets, including inventory, and related contracts in South Louisiana $129 
      Investment in Natural Gas Storage Facilities September 2005 Joint venture with Vulcan Gas Storage LLC to develop and operate natural gas storage facilities. $125(1)
      Link Energy LLC April 2004 The North American crude oil and pipeline operations of Link Energy, LLC (‘‘Link”) $332 
      Capline and Capwood Pipeline Systems March 2004 An approximate 22% undivided joint interest in the Capline Pipeline System and an approximate 76% undivided joint interest in the Capwood Pipeline System $159 
      Shell West Texas Assets August 2002 Basin Pipeline System, Permian Basin Pipeline System and the Rancho Pipeline System $324 
      (1)Represents 50% of the purchase price for the acquisition made by our joint venture. The joint venture completed an acquisition for approximately $250 million during 2005.
      (2)Our interest in the High Island Pipeline System was relinquished in November 2006.
      Pacific Energy Acquisition
      On November 15, 2006 we completed ten acquisitions for aggregate considerationour acquisition of approximately $159.5 million. In addition, in December 2003, we signed a definitive agreement with Shell Pipeline CompanyPacific pursuant to acquire entities owning pipelinean Agreement and terminal assets for $158 million. Following is a brief descriptionPlan of this pendingMerger dated June 11, 2006. The merger-related transactions included: (i) the acquisition acquisitions completed in 2003 that exceeded $15 millionfrom LB Pacific, LP and major acquisitions and dispositions that have occurred since our initial public offering in November 1998.

        Pending Acquisition of Capline and Capwood Pipeline System

              On December 16, 2003, we entered into a definitive agreement to acquire all of Shell Pipeline Company LP's ("SPLC"its affiliates (“LB Pacific”) interests in two entities. The principal assets of the entities are: (i) an approximate 22% undivided jointgeneral partner 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 667-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capline system is operated by Shell Pipeline Company, LP and is oneincentive distribution rights 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 tankersPacific as well as access to LOOP, the Louisiana Offshore Oil Port, the Capline System is a key transporter of sweetapproximately 5.2 million Pacific common units and light sour foreign crude to PADD II. Withapproximately 5.2 million Pacific subordinated units for a total system operating capacity of 1.14$700 million barrels per day, approximately 248,000 barrels per day are subject to the interest being acquired. During 2003, throughput on the interest in the Capline System we are acquiring 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 we are acquiring. 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. After closing, we anticipate that we will assume the operatorship of the Capwood system from SPLC. During 2003, throughput on the interest being acquired averaged approximately 107,000 barrels per day.

              This acquisition is expected to close during the first quarter of 2004. While we believe it is reasonable to expect the acquisition to close in the first quarter of 2004, we can provide no assurance as to when or whether the acquisition will close.

        South Saskatchewan Pipeline System

              In November 2003, we completed(ii) the acquisition of the South Saskatchewan Pipeline System from South Saskatchewan Pipe Line Company.balance of Pacific’s equity through aunit-for-unit exchange in which each Pacific unitholder (other than LB Pacific) received 0.77 newly issued Partnership common units for each


      7

      Pacific common unit. The South Saskatchewan Pipeline System originates approximately 75 miles southwesttotal value 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. 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 assetstransaction was approximately $48 million,$2.5 billion, including the assumption of debt and estimated transaction costs.

        ArkLaTex Pipeline System

              In October 2003, we completed the acquisition Upon completion of the ArkLaTex Pipeline System from Link Energy (formerly EOTT Energy).merger-related transactions, the general partner and limited partner ownership interests in Pacific were extinguished and Pacific was merged with and into the Partnership. The ArkLaTex Pipeline System consists of 240assets acquired in the Pacific acquisition included approximately 4,500 miles of active crude oil pipeline and gathering systems and mainline550 miles of refined products pipelines, and connects to our Red River Pipeline System near Sabine, Texas. Also included in the transaction were 470,000over 13 million barrels of active crude oil and 9 million barrels of refined products storage capacity, the assignmenta fleet of certainapproximately 75 owned or leased trucks and approximately 1.9 million barrels of Link Energy's crude oil supply contracts and crude oilrefined products linefill and working inventory comprising approximately 108,000 barrels.inventory. The total purchase price for thesePacific assets of approximately $21.3 million included approximately $14.0 million of cash paid to Link Energy forcomplement our existing asset base in California, the pipeline system, approximately $2.9 million of cash paid to Link Energy to purchase crude oil linefillRocky Mountains and working inventory, approximately $3.6 million for estimated near-term capital costs and transaction costs and approximately $0.8 million associatedCanada, with the satisfaction of outstanding claims for accounts receivable and inventory balances.

        Iraan to Midland Pipeline System

              In June 2003, the Partnership acquired the Iraan to Midland Pipeline System from a unit of Marathon Ashland Petroleum LLC ("MAP") for aggregate consideration of approximately $17.6 million. The Iraan to Midland Pipeline System is a 16-inch, 95-mile mainline crude oil pipeline that originates in Iraan, Texas and terminates in Midland, Texas. At Midland, the system has the ability to deliver crude oil to our Basin Pipeline System and to the Mesa Pipeline System. In 2002, the Iraan to Midland Pipeline System transported approximately 21,000 barrels per day of crude oil.minimal asset overlap but attractive potential vertical integration opportunities. The results of operations and assets of the Iraan to Midland Pipeline Systemand liabilities from this acquisition (the “Pacific acquisition”) have been included in our consolidated financial statements and our pipeline operations since June 30, 2003.November 15, 2006. The aggregate purchase price allocation related to the Pacific acquisition is preliminary and subject to change. See Note 3 to our Consolidated Financial Statements.

      Other 2006 Acquisitions
      During 2006, we completed six additional acquisitions for aggregate consideration of approximately $565 million. These acquisitions included $13.6 million(i) 100% of the equity interests of Andrews Petroleum and Lone Star Trucking, which provide isomerization, fractionation, marketing and transportation services to producers and customers of natural gas liquids (collectively, the “Andrews acquisition”), (ii) crude oil gathering and transportation assets and related contracts 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.

        South Louisiana Assets

              In June 2003, we completed(“SemCrude”), (iii) interests in various crude oil pipeline systems in Canada and the acquisition ofU.S. including a package of terminalling and gathering assets from El Paso Corporation for approximately $13.4 million, including transaction costs. These assets are located100% interest in southern Louisiana and includethe Bay Marchand-to-Ostrica-to-Alliance (“BOA”) Pipeline, various interests in five pipelinesthe High Island Pipeline System (“HIPS”), 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%64.35% interest in Atchafalayathe Clovelly-to-Meraux (“CAM”) Pipeline L.L.C. In December 2003, we acquired the remaining 662/3% interests in 2 separate transactions totaling $4.4 million.

        Iatan Gathering System

              In March 2003, we completed the acquisition of a West Texas crude oil gathering system, from Navajo Refining Company, L.P. for approximately $24.3 million, including transaction costs. The assets are located in the Permian Basin in West Texas and consist of approximately 315 miles of active crude


      oil gathering lines. The results of operations and assets from this acquisition have been included in our consolidated financial statements and in our pipeline operations segment since March 1, 2003.

        Red River Pipeline System

              In February 2003, we completed the acquisition of a 347-mile crude oil pipeline from BP Pipelines (North America) Inc. for approximately $19.4 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.

        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 8.9 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the "Shell acquisition"). 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."

        Canadian Expansion

              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.

        West Texas Gathering System

              In July 1999, we completed the acquisition of the West Texas Gathering Systemthree refined products pipeline systems 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 2.9 million barrels of tankage located along the system.

        Company.

      Scurlock Permian

              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 920-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.

        Ongoing Acquisition Activities

      Consistent with our business strategy, we are continuously engaged in discussions with potential sellers regarding the possible purchase by us of midstreamassets and operations that are strategic and complementary to our existing operations. Such assets and operations include crude oil related assets, refined products assets, LPG assets and, through our interest in PAA/Vulcan, natural gas storage assets. In addition, we have in the past and intend in the future to evaluate and pursue other energy related assets that have characteristics and opportunities similar to these business lines and enable us to leverage our asset base, knowledge base and skill sets. Such acquisition efforts may involve participation by us in processes that have been made public and involve a number of potential buyers, and are commonly referred to as "auction"“auction” processes, as well as situations wherein 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, wouldcould have a material effect on our financial condition and results of operations.

              We

      Crude Oil Market Overview
      Our assets and our business strategy are currently involved in advanced discussions with a potential seller regarding the purchasedesigned to service our producer and refiner customers by us ofaddressing regional crude oil pipeline, terminalling, storagesupply and gathering and marketing assets for an aggregate purchase price, including assumed liabilities and obligations, ranging from $300 million to $400 million. Such transaction is subject to confirmatory due diligence, negotiation of a mutually acceptable definitive purchase and sale agreement, regulatory approval and approval of both our board of directors anddemand imbalances that of the seller.

              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 $0.4 million in deferred costs at December 31, 2003. We estimate that our deferred acquisition costs will increaseexist in the first quarter of 2004 byUnited States and Canada. According to the Energy Information Administration (“EIA”), during the twelve months ended October 2006, the United States consumed approximately $0.7 million. 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.

        Shutdown and Partial Sale of Rancho Pipeline System

              We acquired 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, we completed transactions whereby we transferred all of our ownership interest in approximately 240 miles of the total 458 miles of the pipeline in exchange for $4.0 million and approximately 500,000 barrels of crude oil tankage in West Texas. The remaining portion will either be sold or salvaged. No gain or loss has been recorded on the shutdown of the Rancho System or these transactions.

        All American Pipeline Linefill Sale and Asset Disposition

              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 5.215.2 million barrels of crude oil inper day, while only producing 5.1 million barrels per day. Accordingly, the segmentUnited States relies on foreign imports for nearly 66% of the pipeline. We soldcrude oil used by U.S. domestic refineries. This imbalance represents a continuing trend. Foreign imports of crude oil into the U.S. have tripled over the last 21 years, increasing from 3.2 million barrels per day in 1985 to 10.2 million barrels per day for the 12 months ended October 2006, as U.S. refinery demand has increased and domestic crude oil production has declined due to natural depletion.

      The Department of Energy segregates the United States into five Petroleum Administration Defense Districts (“PADDs”) which are used by the energy industry for reporting statistics regarding crude oil supply and demand. The table below sets forth supply, demand and shortfall information for each PADD for the twelve months ended October 2006 and is derived from information published by the EIA (see EIA website at www.eia.doe.gov).


      8

                   
        Regional
      		  Refinery
      		  Supply
      		 
      Petroleum Administration Defense District
      		 Supply  Demand  Shortfall 
        (Millions of barrels per day) 
       
      PADD I (East Coast)  0.0   1.5   (1.5)
      PADD II (Midwest)  0.5   3.3   (2.8)
      PADD III (South)  2.8   7.2   (4.4)
      PADD IV (Rockies)  0.3   0.5   (0.2)
      PADD V (West Coast)  1.5   2.7   (1.2)
                   
      Total U.S. 
      		  5.1   15.2   (10.1)
      Although PADD III has the largest supply shortfall, PADD II is believed to be the most critical region with respect to supply and transportation logistics because it is the largest, most highly populated area of the U.S. that does not have direct access to oceanborne cargoes.
      Over the last 21 years, crude oil production in PADD II has declined from approximately 1.0 million barrels per day to approximately 450,000 barrels per day. Over this same time period, refinery demand has increased from approximately 2.7 million barrels per day in 1985 to 3.3 million barrels per day for the twelve months ended October 2006. As a result, the volume of crude oil transported into PADD II has increased 71%, from 1.7 million barrels per day to 2.9 million barrels per day. This aggregate shortfall is principally supplied by direct imports from Canada to the north and from the Gulf Coast area and the Cushing Interchange to the south.
      The logistical transportation, terminalling and storage challenges associated with regional volumetric supply and demand imbalances are further complicated by the fact that crude oil from November 1999different sources is not fungible. The crude slate available to February 2000U.S. refineries consists of a substantial number of different grades and varieties of crude oil. Each crude grade has distinguishing physical properties, such as specific gravity (generally referred to as light or heavy), sulfur content (generally referred to as sweet or sour) and metals content as well as varying economic attributes. In many cases, these factors result in the need for net proceedssuch grades to be batched or segregated in the transportation and storage processes, blended to precise specifications or adjusted in value. In addition, from time to time, natural disasters and geopolitical factors, such as hurricanes, earthquakes, tsunamis, inclement weather, labor strikes, refinery disruptions, embargoes and armed conflicts, may impact supply, demand and transportation and storage logistics.
      Refined Products Market Overview
      Once crude oil is transported to a refinery, it is broken down into different petroleum products. These “refined products” fall into three major categories: fuels such as motor gasoline and distillate fuel oil (diesel fuel); finished non-fuel products such as solvents and lubricating oils; and feedstocks for the petrochemical industry such as naphtha and various refinery gases. Demand is greatest for products in the fuels category, particularly motor gasoline.
      The characteristics of the gasoline produced depend upon the setup of the refinery at which it is produced and the type of crude oil that is used. Gasoline characteristics are also impacted by other ingredients that may be blended into it, such as ethanol. The performance of the gasoline must meet industry standards and environmental regulations that vary based on location.
      After crude oil is refined into gasoline and other petroleum products, the products must be distributed to consumers. The majority of products are shipped by pipeline to storage terminals near consuming areas, and then loaded into trucks for delivery to gasoline stations or other end users. Some of the products which are used as feedstocks are typically transported by pipeline to chemical plants.
      Demand for refined products is increasing and is affected by price levels, economic growth trends and, to a lesser extent, weather conditions. According to the EIA, consumption of refined products in the United States has risen steadily from approximately $100.015.7 million barrels per day in 1985 to approximately 20.7 million barrels per day for the twelve months ended October 2006, an increase of 31%. By 2030, the EIA estimates that the U.S. will consume approximately 27.6 million barrels per day of refined products, an increase of 33% over the last twelve

      9

      months’ levels. We believe that the additional demand will be met by growth in the capacity of existing refineries through large expansion projects and “capacity creep” as well as increased imports of refined products, both of which werewe believe will generate incremental demand for midstream infrastructure, such as pipelines and terminals.
      We believe that demand for refined products pipeline and terminalling infrastructure will also increase as a result of:
      • multiple specifications of existing products (also referred to as boutique gasoline blends);
      • specification changes to existing products, such as ultra low sulfur diesel;
      • new products, such as bio-fuels;
      • the aging of existing infrastructure; and
      • the potential reduction in storage capacity due to regulations governing the inspection, repair, alteration and construction of storage tanks.
      We intend to grow our asset base in the refined products business through expansion projects and future acquisitions. Consistent with our plan to apply our proven business model to these assets, we also intend to optimize the value of our refined products assets and better serve the needs of our customers by building a complementary refined products supply and marketing business.
      LPG Products Market Overview
      LPGs are a group ofhydrogen-based gases that are derived from crude oil refining and natural gas processing. They include ethane, propane, normal butane, isobutane and other related products. For transportation purposes, these gases are liquefied through pressurization. LPG is also imported into the U.S. from Canada and other parts of the world.
      LPGs are principally used as feedstock for petrochemical production processes. Individual LPG products have specific uses. For example, propane is used for working capital purposes.home heating, water heating, cooking, crop drying and tobacco curing. As a motor fuel, propane is burned in internal combustion engines that power over-the-road vehicles, forklifts and stationary engines. Ethane is used primarily as a petrochemical feedstock. Normal butane is used as a petrochemical feedstock, as a blend stock for motor gasoline, and to derive isobutane through isomerization. Isobutane is principally used in refinery alkylation to enhance the octane content of motor gasoline or in the production of isooctane or other octane additives. Certain LPGs are also used as diluent in the transportation of heavy oil, particularly in Canada.
      According to the EIA, consumption of LPGs in the United States has risen steadily from approximately 1.6 million barrels per day in 1985 to approximately 2.1 million barrels per day for the twelve months ended October 2006, an increase of 33%. By 2030, the EIA estimates that the U.S. will consume approximately 2.4 million barrels per day of LPGs, an increase of 13% over the last twelve months’ levels. We recognizedbelieve that the additional demand will result in an aggregate gainincreased demand for LPG infrastructure, including pipelines, storage facilities, processing facilities and import terminals.
      We intend to grow our asset base in the LPG business through expansion projects and future acquisitions. We believe that our asset base, which is principally located in the upper tier of the U.S., Oklahoma and California, provides flexibility in meeting the needs of our customers and opportunities to capitalize on regional supply/demand imbalances in LPG markets.
      Natural Gas Storage Market Overview
      After treatment for impurities such as carbon dioxide and hydrogen sulfide and processing to separate heavier hydrocarbons from the gas stream, natural gas from one source generally is fungible with natural gas from any other source. Because of its fungibility and physical volatility and the fact that it is transported in a gaseous state, natural gas presents different logistical transportation challenges than crude oil and refined products; however, we believe the U.S. natural gas supply and demand situation will ultimately face storage challenges very similar to those that exist in the North American crude oil sector. We believe these factors will result in an increased need and an


      10

      attractive valuation for natural gas storage facilities in order to balance market demands. From 1990 to 2005, domestic natural gas production grew approximately $44.6 million,2% while domestic natural gas consumption rose approximately 15%, resulting in an approximate 175% increase in the domestic supply shortfall over that time period. In addition, significant excess domestic production capacity contractually withheld from the market bytake-or-pay contracts between natural gas producers and purchasers in the late 1980s and early 1990s has since been eliminated. This trend of an increasing domestic supply shortfall is expected to continue. By 2030, the EIA estimates that the U.S. will require approximately 5.5 trillion cubic feet of annual net natural gas imports (or approximately 15 billion cubic feet per day) to meet its demand, nearly 1.4 times the 2005 annual shortfall.
      The vast majority of the projected supply shortfall is expected to be met with imports of liquefied natural gas (LNG). According to the Federal Energy Regulatory Commission (“FERC”) as of January 2007, plans for 34 new LNG terminals in the United States and Bahamas have been proposed, 17 of which approximately $28.1 million was recognizedare to be situated along the Gulf Coast. Of the 17 proposed Gulf Coast facilities, three are under construction, nine have been approved by the appropriate regulatory agencies, and five have been proposed to the appropriate regulatory agencies. These facilities will be used to re-gasify the LNG prior to shipment in 2000pipelines to natural gas markets.
      Normal depletion of regional natural gas supplies will require additional storage capacity to pre-position natural gas supplies for seasonal usage. In addition, we believe that the growth of LNG as a supply source will also increase the demand for natural gas storage as a result of inconsistent surges and shortfalls in connectionsupply based on LNG tanker deliveries, similar in many respects to the issues associated with waterborne crude oil imports. LNG shipments are exposed to a number of risks related to natural disasters and geopolitical factors, including hurricanes, earthquakes, tsunamis, inclement weather, labor strikes and facility disruptions, which can impact supply, demand and transportation and storage logistics. These factors are in addition to the salealready dramatic impact of the linefill.

      seasonality and regional weather issues on natural gas markets.

      Description of Segments and Associated Assets

      Our business activities are conducted through two primarythree segments Pipeline Operations— Transportation, Facilities and Gathering, Marketing, TerminallingMarketing. We have an extensive network of transportation, terminalling and Storage Operations. Our operations are conductedstorage facilities at major market hubs and in approximately 40 stateskey oil producing basins and crude oil, refined product and LPG transportation corridors in the United States and five provinces in Canada. The majority of our operations are conducted in Texas, Oklahoma, California, 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:

      segments.

      Pipeline OperationsTransportation

              We own and operate approximately 7,000 miles

      Our transportation segment operations generally consist of gathering and mainlinefee-based activities associated with transporting volumes of crude oil and refined products on pipelines locatedand gathering systems.
      As of December 31, 2006, we employed a variety of owned or leased long-term physical assets throughout the United States and Canada. Our activities from pipeline operations generally consistCanada in this segment, including approximately:
      • 20,000 miles of active pipelines and gathering systems;
      • 30 million barrels of tank capacity used primarily to facilitate pipeline movements; and
      • 57 transport and storage barges and 30 transport tugs through our 50% interest in Settoon Towing.
      We generate revenue through a combination of transporting crude oil for a fee,tariffs, third party leases of pipeline capacity, transportation fees, barrel exchanges and buy/sell arrangements.

      We also include in this segment our equity earnings from our investments in the Butte and Frontier pipeline systems, in which we own minority interests, and Settoon Towing, in which we own a 50% interest.

      Substantially all of our pipeline systems are controlled or monitored from one of twofour central control rooms with computer systems designed to continuously monitor real-time operational data, includingsuch as 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-controlledremote controlled shut-down of the majority of our pump stations on the pipeline systems. Pump stations, storage facilities and meter measurement


      11

      points along the pipeline systems are linked by telephone, satellite, radio, fiber optic cable, telephone, or a combination thereof to provide communications for remote monitoring and in some instances operational control, which reduces our requirement for full-time site personnel at most of these locations.

      We perform scheduled maintenancemake repairs on alland replacements of our mainline 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 streamand refined product streams and other protection systems typically used in the industry. Maintenance facilities containing spare parts and equipment for pipe repairs, spare parts andas well as 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, provincial and local laws and regulations, standards prescribed by the American Petroleum Institute (“API”), the Canadian Standards Association and accepted industry practice.practice as required or considered appropriate under the circumstances. See "—Regulation—“— Regulation — Pipeline and Storage Regulation."

      ”

      Following is a descriptiontabular presentation of all of our majoractive pipeline assets in the United States and Canada, grouped by geographic location:
                   
               2006 Average
      		 
            System
      		  Net Barrels
      		 
      Region
      		 
      Pipeline/Gathering Systems
      		 % Ownership Miles  per Day(1) 
       
      Southwest US
      		 Basin 87%  519   332,000 
        Dollarhide 100%  24   5,000 
        El Paso — Albuquerque (refined products) 100%  257   28,000 
        Garden City 100%  63   10,000 
        Hardeman 100%  107   4,000 
        Iatan 100%  360   21,000 
        Iraan 100%  98   31,000 
        Merkel 100%  128   4,000 
        Mesa 63%  80   31,000 
        New Mexico 100%  1,163   81,000 
        Permian Basin Gathering 100%  780   59,000 
        Spraberry Gathering 100%  727   42,000 
        Texas 100%  1,498   75,000 
        West Texas Gathering 100%  738   85,000 
      Western US
      		 All American 100%  136   49,000 
        Line 63 100%  323   86,000 
        Line 2000 100%  151   73,000 
        San Joaquin Valley 100%  77   88,000 
      US Rocky Mountain
      		 AREPI 100%  42   46,000 
        Beartooth 50%  76   15,000 
        Bighorn 58%  336   15,000 
        Butte(3) 22%  370   18,000 
        Frontier 22%  290   46,000 
        Glacier(3) 21%  614   20,000 
        North Dakota/Trenton 100%  731   89,000 
        Rocky Mountain Gathering 100%  400   27,000 
        Rocky Mountain Products (refined products) 100%  554   61,000 
        Salt Lake City Core 100%  960   45,000 
      US Gulf Coast
      		 ArkLaTex 100%  87   21,000 
        Atchafalaya 100%  35   20,000 


      12

      Southwest U.S.

              Basin Pipeline System.    We acquired an approximate 87% undivided joint interest in the Basin System in the Shell acquisition. The Basin System

                   
               2006 Average
      		 
            System
      		  Net Barrels
      		 
      Region
      		 
      Pipeline/Gathering Systems
      		 % Ownership Miles  per Day(1) 
       
        BOA 100%  107   82,000 
        Bridger Lakes 100%  19   1,000 
        CAM (Segment I/Segment II) 60%/0%  47   131,000 
        Capline(3) 22%  633   160,000 
        Capwood/Patoka 76%  58   99,000 
        Cocodrie 100%  66   6,000 
        East Texas 100%  9   8,000 
        Eugene Island 100%  66   11,000 
        Golden Meadow 100%  37   3,000 
        Deleck 100%  119   29,000 
        Mississippi/Alabama 100%  837   87,000 
        Pearsall 100%  62   2,000 
        Red River 100%  359   13,000 
        Red Rock 100%  54   3,000 
        Sabine Pass 100%  33   12,000 
        Southwest Louisiana 100%  205   4,000 
        Turtle Bayou 100%  14   3,000 
      Central US
      		 Cushing to Broome 100%  103   73,000 
        Midcontinent 100%  1,197   35,000 
        Oklahoma 100%  1,629   59,000 
                   
          Domestic Total    17,378   2,348,000 
                   
      Canada
      		 Cactus Lake(2) 100%  115   16,000 
        Cal Ven 100%  148   16,000 
        Joarcam 100%  31   4,000 
        Manito 100%  381   61,000 
        Milk River 100%  33   96,000 
        Rangeland 100%  938   66,000 
        South Saskatchewan 100%  344   47,000 
        Wapella 100%  73   11,000 
        Wascana 100%  107   3,000 
                   
          Canada Total    2,170   320,000 
                   
             Total    19,548   2,668,000 
                   
      (1)Represents average volumes for the entire year of 2006.
      (2)For January through March 2006, our interest was 15%; we acquired the remaining interest in March 2006.
      (3)Non-operated pipeline.

      13

      Below is a 514-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 263,000 barrels per day (net todetailed description of our interest) during 2003. 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 Fallsmore significant transportation 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 February 2004, we announced plans to expand a 345-mile section of the system. The section to be expanded extends from Colorado City, Texas to our Cushing Terminal. Upon the completion of this estimated $1.1 million expansion, the capacity of this section will increase 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—assets.
      Major Transportation Regulation."Assets

              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 87,000 barrels per day in 2003. 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 2.9 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 927 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 2003. The Permian Basin System includes approximately 3.2 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 System consists of approximately 920 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 year ended December 31, 2003, the Spraberry Pipeline System gathered approximately 38,000 barrels per day of crude oil. The Spraberry Pipeline System also includes approximately 364,000 barrels of tank capacity located along the pipeline.

              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 2003, 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 and in Midland.

              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, 95-mile mainline crude oil pipeline that originates in Iraan, Texas and terminates in Midland, Texas. At Midland, the system has the ability to deliver crude oil to our Basin Pipeline System and to the Mesa Pipeline System. In the last six months of 2003, deliveries averaged approximately 30,000 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 315 miles of active crude oil gathering lines. During the last ten months of 2003, volumes on this system averaged 23,000 barrels per day.

        Western U.S.

      All American Pipeline System.System

      The segment of the All American Pipeline that we retained following the sale of the line segment to El Paso is a common carriercommon-carrier crude oil pipeline system that transports crude oil produced from certain outer continental shelf, or OCS, fields offshore California via connecting pipelines to locationsrefinery markets in California. See "—Acquisitions and Dispositions—All American Pipeline Linefill Sale and Asset Disposition." This segment is subject to tariff rates regulated by the FERC.

              We own and operate the segment of theThe system that extends approximately 10 miles along the California coast from Las Flores to Gaviota (24-inch(24-inch diameter pipe) and continues from Gaviota approximately 130126 miles to our station in Emidio, California (30-inch(30-inch diameter pipe). Between Gaviota



      and our Emidio Station, the All American Pipeline interconnects with our San Joaquin Valley or SJV,(or SJV) Gathering System, Line 2000 and Line 63, as well as variousother third party intrastate pipelines, includingpipelines. The system is subject to tariff rates regulated by the Unocap Pipeline System, the Shell Pipeline Company, L.P. and the Pacific Pipeline.

      FERC.

      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 Plains Exploration and Production Company ("PXP") and other producers whichthat together own approximately 75%70% 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 whothat do not have contracts with us have no other existing means of transporting their production and, therefore, ship their volumes on the All American Pipeline at the postedfiled tariffs. Volumes attributable to PXP are purchasedFor 2006 and sold to a third party under our marketing agreement with PXP before such volumes enter2005, tariffs on the All American Pipeline. See Item 13. "Certain RelationshipsPipeline averaged $2.07 per barrel 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$1.87 per barrel. Effective January 1, 2004, based on the contractual escalator, the average tariff increased to $1.81 per barrel.barrel, respectively. The agreements do not require these owners to transport a minimum volume. AThese agreements, which had an initial term expiring in August 2007, include an annual one year evergreen provision that requires one year’s advance notice to cancel.
      With the acquisition of Line 2000 and Line 63, a significant portion of our transportation segment profit is derived from the pipeline transportation marginsbusiness associated with these two fields. For the year ended December 31, 2003, approximately $29 million, or 13%, of our aggregate revenues less direct field operating costs was attributable to the Santa Ynez field and approximately $8 million, or 4% was attributable to the Point Arguello field.

              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 the Partnership has 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,fields located in 1995 to 46,000 and 13,000 average daily barrels, respectively, for the year ended December 31, 2003.San Joaquin Valley. We expectestimate that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. Aa 5,000 barrel per day decline in volumes shipped from thesethe outer continental shelf fields would result in a decrease in annual pipeline tariff revenuestransportation segment profit of approximately $3.3 million, based on a tariff of $1.81 per barrel.

              In October 2003, PXP announced that it had received all of the necessary permits to develop a portion of the Rocky Point structure that is accessible$6.1 million. A similar decline in volumes shipped from the Point Arguello platforms and it appears that they will commence drilling activitiesSan Joaquin Valley would result in the second quarter of 2004. Such drilling activities, if successful, are not expected to have a significant impact on pipeline shipments on our All American Pipeline systeman estimated $3.2 million decrease 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.

      annual transportation segment profit.


      The table below sets forth the historical volumes received from both of these fields for the past five years.

      years:
       
      		 Year Ended December 31,
       
      		 2003
      		 2002
      		 2001
      		 2000
      		 1999
       
      		 (barrels in thousands)

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

                           
        Year Ended December 31, 
        2006  2005  2004  2003  2002 
        (Barrels in thousands) 
       
      Average daily volumes received from:                    
      Point Arguello (at Gaviota)  9   10   10   13   16 
      Santa Ynez (at Las Flores)  40   41   44   46   50 
                           
      Total  49   51   54   59   66 
                           

              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 AmericanBasin Pipeline at the Pentland station. The SJV Gathering System also includes approximately 600,000 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.

       
      		 Year Ended December 31,
       
      		 2003
      		 2002
      		 2001
      		 2000
      		 1999
       
      		 (barrels in thousands)

      Total average daily volumes 78 73 61 60 84

              Butte Pipeline System.

      We own an approximate 22% equity87% undivided joint interest in Butte Pipe Line Company, which in turn ownsand act as operator of the ButteBasin Pipeline System,System. The Basin system is a 373-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 volumesprimary route for the Butte Pipeline System during 2003 were approximately 71,000 barrels oftransporting Permian Basin crude oil per day (approximately 16,000to Cushing, Oklahoma, for further delivery to Mid-Continent and Midwest refining centers. The Basin system is a519-mile mainline, telescoping crude oil system with a capacity ranging from approximately 144,000 barrels per day net to our 22% interest). The operator of the system is Bridger Pipeline.

              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 35 miles of pipe ranging from 4 to 10 inches in diameter and has a throughput capacity of approximately 26,000400,000 barrels of crude oil per day. In 2003, 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. In 2003, the Ferriday Pipeline System delivered approximately 7,000 barrels of crude oil per day to third party pipelines that supplied refiners independing on the Midwest. The Ferriday Pipelinesegment. System also includesthroughput (as measured by system deliveries) was approximately 332,000 barrels per day (net to our interest) during 2006. Within the current operating range, a 20,000 barrel per day decline in volumes shipped on the Basin system would result in a decrease in annual transportation segment profit of tank capacity located along the pipeline.

      approximately $1.8 million.


              La Gloria Pipeline System.

      The La Gloria Pipeline System, acquired in the Scurlock acquisition, is a proprietary crude oil pipelineBasin system that in 2003 transported approximately 24,000 barrelsconsists of four primary movements of crude oil per dayoil: (i) barrels that are shipped from Jal, New Mexico to Crown Central's refinery in Longview, Texas. Crown Central's deliveriesthe West Texas markets of Wink and Midland; (ii) barrels that are subjectshipped from Midland to a throughput


      14

      connecting carriers at Colorado City; (iii) barrels that are shipped from Midland and deficiency agreement, which extends through 2004.

              Red River Pipeline System.    The Red River Pipeline System, acquired in 2003, is a 347-mile crude oil pipeline systemColorado City to connecting carriers at either Wichita Falls or Cushing; and (iv) foreign and Gulf of Mexico barrels that originatesare delivered into Basin at Sabine in East Texas,Wichita Falls and terminates near Cushing, Oklahoma. The Red River system has a capacity of updelivered to 22,000 barrels of crude oil per day, depending upon the type of crude oil being transported. During 2003, the system transported approximately 8,000 barrels of crude oil per day.connecting carriers at Cushing. The system also includes approximately 645,0005.5 million 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(4.8 million barrels, of active crude oil storage capacity. During the fourth quarter of 2003, volumes transported averaged 13,000 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 28 miles of active 8-inch crude oil and condensate pipelines. In the last half of 2003, the system transported approximately 12,000 barrels per day of crude oil and condensate.

              Eugene Island Flowline System.    We own from 38%-56% (depending upon the segment and throughput level) of the Eugene Island Flowline System ("EIFS"). 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 last half of 2003 were approximately 16,000 barrels per day (8,200 barrels per day, net to our interest) of crude oil.

              Illinois Basin Pipeline System.    The Illinois Basin Pipeline System, acquired with the Scurlock acquisition, consists of common carrier pipeline and gathering systems and truck injection facilities in southern Illinois. The Illinois Basin Pipeline System consists of approximately 80 miles of pipe of varying diameter and in 2003 delivered approximately 2,900 barrels of crude oil per day to third party pipelines that supply refiners in the Midwest. For the year ended December 31, 2003, approximately 2,500 barrels of crude oil per day of the supply on this system came from fields operated by PXP.

              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 68,000 barrels of crude oil and condensate per day in 2003.

              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 104,000 barrels of crude oil per day in 2003.



              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 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. In 2003, the North Saskatchewan Pipeline System delivered approximately 6,000 barrels of crude oil and condensate per day into the Manito Pipeline. Our ownership interest in the North Saskatchewan Pipeline System is approximately 36%.

              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. In 2003, the Cactus Lake/Bodo Pipeline System transported approximately 26,000 barrels per day (approximately 3,000 barrels per day, net to our interest) of crude oil storage capacity located along the system. In 2004, we expanded an approximate425-mile section of the system from Midland to Cushing. With the completion of this 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 FERC.

      Capline/Capwood Pipeline Systems
      The Capline Pipeline System, in which we own a 22% undivided joint interest, is a633-mile,40-inch mainline crude oil pipeline originating in St. James, Louisiana, and condensate. Our ownership interestterminating in Patoka, Illinois. 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. Shell is the operator of this system. Capline has direct connections to a significant amount of crude production in the Cactus LakeGulf of Mexico. In addition, with its two active docks capable of handling600,000-barrel tankers as well as access to 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 our interest. During 2006, throughput on our interest averaged approximately 160,000 barrels per day. A 10,000 barrel per day decline in volumes shipped on the Capline system would result in a decrease in our annual transportation segment profit of approximately $1.3 million.
      The Capwood Pipeline System, in which we own a 76% undivided joint interest, is 13.125%a58-mile,20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. 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 our ownershipinterest. The system has the ability to deliver crude oil at Wood River to several other PADD II refineries and pipelines. Movements on the Capwood system are driven by the volumes shipped on Capline as well as by volumes of Canadian crude that can be delivered to Patoka via the Mustang Pipeline. PAA assumed the operatorship of the Capwood system from Shell Pipeline Company LP at the time of purchase. During 2006 throughput net to our interest averaged approximately 99,000 barrels per day.
      Line 2000
      We own and operate Line 2000, an intrastate common carrier crude oil pipeline that originates at our Emidio Pump Station and transports crude oil produced in the BodoSan Joaquin Valley and California outer continental shelf to refineries and terminal facilities in the Los Angeles Basin. Line 2000 is a151-mile trunk pipeline with a throughput capacity of 130,000 barrels per day. For the full year of 2006, throughput on Line 2000 averaged approximately 73,000 barrels per day.
      Line 63
      The Line 63 system is an intrastate common carrier crude oil pipeline system that transports crude oil produced in the San Joaquin Valley and California outer continental shelf to refineries and terminal facilities in the Los Angeles Basin and in Bakersfield. The Line 63 system consists of a107-mile trunk pipeline, originating at our Kelley Pump Station in Kern County, California and terminating at our West Hynes Station in Long Beach, California. The Line 63 system includes 60 miles of distribution pipelines in the Los Angeles Basin and in the Bakersfield area, 156 miles of gathering pipelines in the San Joaquin Valley, and 22 storage tanks with approximately 1.2 million barrels of storage capacity. These storage assets, the majority of which are located in the San Joaquin Valley, are used primarily to facilitate the transportation of crude oil on the Line 63 system. Line 63 has a throughput capacity of approximately 105,000 barrels per day. For the full year of 2006, throughput on Line 63 averaged approximately 86,000 barrels per day.


      15

      Rangeland System
      The Rangeland system includes the Mid Alberta Pipeline and the Rangeland Pipeline. The Mid Alberta Pipeline is 76.25%. a138-mile proprietary pipeline with a throughput capacity of approximately 50,000 barrels per day if transporting light crude oil. The Mid Alberta Pipeline originates in Edmonton, Alberta and terminates in Sundre, Alberta where it connects to the Rangeland Pipeline. The Rangeland Pipeline is a proprietary pipeline system that consists of approximately 800 miles of gathering and trunk pipelines and is capable of transporting crude oil, condensate and butane either north to Edmonton, Alberta via third-party pipeline connections or south to the U.S./Canadian border near Cutbank, Montana where it connects to our Western Corridor system. The trunk pipeline from Sundre, Alberta to the U.S./Canadian border consists of approximately 250 miles of trunk pipelines and has a current throughput capacity of approximately 85,000 barrels per day if transporting light crude oil. The trunk system from Sundre, Alberta north to Rimbey, Alberta is a bi-directional system that consists of three parallel trunk pipelines: a56-mile pipeline for low sulfur crude oil, a63-mile pipeline for high sulfur crude oil, and a56-mile pipeline for condensate and butane. From Rimbey, third-party pipelines move product north to Edmonton. For the full year of 2006, 22,500 barrels per day of crude oil was transported on the segment of the pipeline from Sundre north to Edmonton and 43,500 barrels per day was transported on the pipeline from Sundre south to the United States.
      Western Corridor System
      The Western Corridor system is an interstate and intrastate common carrier crude oil pipeline system that consists of 1,012 miles of pipelines extending from the U.S./Canadian border near Cutbank, Montana, where it receives deliveries from our Rangeland Pipeline and the Cenex Pipeline, and terminates at Guernsey, Wyoming with connections to our Salt Lake City Core system, the Frontier Pipeline and various third-party pipelines. The Western Corridor system consists of three contiguous trunk pipelines: Glacier Pipeline, Beartooth Pipeline and Big Horn Pipeline.
      • Glacier Pipeline.  We own a 20.8% undivided interest in Glacier Pipeline, which provides us with approximately 25,000 barrels per day of throughput capacity. Glacier Pipeline consists of 614 miles of two parallel crude oil pipelines, a277-mile,12-inch trunk pipeline, a288-mile,8-inch and10-inch trunk pipeline, and a49-mile12-inch loop line, all extending from the Canadian border and Cutbank, Montana to Billings, Montana. Shipments on Glacier Pipeline can be delivered either to refineries in Billings and Laurel, Montana or into our Beartooth pipeline. For the full year of 2006, our throughput on Glacier Pipeline was approximately 20,000 barrels per day. ConocoPhillips Pipe Line Company is the operator of the Glacier Pipeline.
      • Beartooth Pipeline.  We own a 50% undivided interest in Beartooth Pipeline, which provides us with approximately 25,000 barrels per day of throughput capacity. Beartooth Pipeline is a76-mile,12-inch trunk pipeline from Billings, Montana to Elk Basin, Wyoming. Beartooth Pipeline was constructed to connect our Glacier Pipeline with our Big Horn Pipeline where all shipments are delivered. For the full year of 2006, our throughput on Beartooth Pipeline was approximately 15,000 barrels per day. We operate the Beartooth Pipeline.
      • Big Horn Pipeline.  We own a 57.6% undivided interest in Big Horn Pipeline, which provides us with approximately 33,900 barrels per day of throughput capacity. Big Horn Pipeline consists of a231-mile,12-inch trunk pipeline from Elk Basin, Wyoming to Casper, Wyoming and a105-mile,12-inch trunk pipeline from Casper, Wyoming to Guernsey, Wyoming. Shipments on our Big Horn Pipeline can be delivered either to Wyoming refineries directly, into Frontier Pipeline at Casper, Wyoming or into the Salt Lake City Core system, the Suncor Pipeline, or Platte Pipeline at Guernsey, Wyoming. For the full year of 2006, our interest in throughput on Big Horn Pipeline was approximately 15,000 barrels per day. We operate the Big Horn Pipeline.
      We also own various undivided interests in 22 storage tanks along the lateral lines in these systems.Western Corridor System that provide us with a total of approximately 1.3 million barrels of storage capacity.


      16

              Wascana Pipeline System.Salt Lake City Core System    The Wascana Pipeline System, acquired in
      We own and operate the Murphy acquisition, isSalt Lake City Core system, an NEB-regulated system located in Saskatchewan, Canada. The Wascana Pipeline System is a 107-mileinterstate and intrastate common carrier crude oil pipeline system that connects to the Bridger Pipeline system at the United States border near Raymond, Montana. In 2003, the Wascana Pipeline System transported approximately 9,000 barrels oftransports crude oil per day.

              Wapella Pipeline System.produced in Canada and the U.S. Rocky Mountain region primarily to refiners in Salt Lake City. The Wapella Pipeline System isSalt Lake City Core system consists of 960 miles of trunk pipelines with a 79 mile, NEB-regulated system located in southeastern Saskatchewan and southwestern Manitoba. In 2003, the Wapella Pipeline System deliveredcombined throughput capacity of approximately 10,000114,000 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 203Salt Lake City, 209 miles of gathering lines ranging in diameter from three to twelve inches. During the periodpipelines, and 32 storage tanks with a total of 2003 that we owned the system, it transported approximately 52,0001.4 million barrels of storage capacity. This system originates in Ft. Laramie, Wyoming, receives deliveries from the Western Corridor system at Guernsey, Wyoming and can deliver to Salt Lake City, Utah and Rangely, Colorado. For the full year of 2006, approximately 45,000 barrels per day were delivered to Salt Lake City directly through our pipelines and of this amount approximately 11,600 barrels per day were delivered indirectly through connections to a Chevron pipeline. We are constructing a95-mile expansion of this system to Salt Lake City, which is scheduled to be completed in early 2008. When completed, the pipeline will have an estimated capacity of 120,000 barrels per day. The cost of this project is supported by10-year transportation contracts that have been executed with four Salt Lake City refiners. Also, in February 2007, we signed a letter of intent to sell a 25% interest in this line to Holly Energy Partners, L.P. As part of this agreement, Holly Refining and Marketing will enter into a10-year transportation agreement on terms consistent with the four previously committed refiners. Plains’ portion of the total project cost is estimated to be $75 million, of which approximately $55 million is scheduled to be spent in 2007.

      Cheyenne Pipeline
      Pursuant to a transportation agreement, we are constructing a16-inchcrude oil pipeline, approximately 93 miles in length, from Fort Laramie to Cheyenne, Wyoming, in exchange for a ten-year firm commitment to ship 35,000 barrels per day on the new pipeline and lease approximately 300,000 barrels of storage capacity at Fort Laramie. The project also includes 10 miles of a24-inch pipeline from Guernsey to Fort Laramie. The total project cost is estimated to be $59 million of which $34 million is the estimated remaining project cost to be incurred in 2007. The project is expected to be completed by the end of the second quarter of 2007. Initial capacity will be 55,000 barrels per day.
      Rocky Mountain Products Pipeline System
      The Rocky Mountain Products Pipeline System consists of a554-mile refined products pipeline extending from Casper, Wyoming east to Rapid City, South Dakota and south to Colorado Springs, Colorado. The Rocky Mountain Products Pipeline originates near Casper, Wyoming, where it serves as a connecting point with Sinclair’s Little America Refinery and the ConocoPhillips Seminole Pipeline, which transports product from Billings, Montana area refineries. The system continues to Douglas, Wyoming where it branches off to serve our Rapid City, South Dakota terminal approximately 190 miles away. This segment also receives product from Wyoming Refining Company via a third-party pipeline at a connection located near the border of Wyoming and South Dakota. From Douglas, Wyoming, the Rocky Mountain Products Pipeline continues south to our terminals at Cheyenne, Wyoming, where it receives refined products from a refinery via a third-party pipeline, and continues on to Denver, Colorado and Colorado Springs, Colorado. Our Denver terminal also receives refined products from Sinclair Pipeline. The various segments of the Rocky Mountain Products Pipeline have a combined throughput capacity of 85,000 barrels per day. At Regina,For the full year of 2006, our throughput on the Rocky Mountain Products Pipeline System was approximately 61,000 barrels per day (average for the entire year). The Rocky Mountain Products Pipeline System includes products terminals at Rapid City, South Dakota, Cheyenne, Wyoming and Denver and Colorado Springs, Colorado with a combined storage capacity of 1.7 million barrels.
      El Paso to Albuquerque System
      The El Paso to Albuquerque refined products pipeline system can deliveris one of three refined products pipeline systems located in Texas and New Mexico. The El Paso to Albuquerque Products Pipeline system is a 257-mile system originating in El Paso, Texas, and terminating in Albuquerque, New Mexico, with approximately 28,200 barrels per day of throughput capacity. The El Paso to Albuquerque system receives various types of refined product at its origination station from Western Refining and Navajo Refining, and delivers product to third party terminals in Belen and Albuquerque, New Mexico. For the full year of 2006, our throughput on the El Paso to Albuquerque system was approximately 28,000 barrels per day.


      17

      Facilities
      Our facilities segment generally consists of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, to the Enbridge Pipeline Systemrefined products 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.


        Gathering and Marketing Operations

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

        •
        purchasing crude oil from producers at the wellhead and in bulk from aggregators at major pipeline interconnects and trading locations;

        •
        transporting this crude oil on our own proprietary gathering assets and our common carrier pipelines or, when necessary or cost effective, assets owned and operated by third parties;

        •
        exchanging this crude oil for another grade of crude oil or at a different geographic location, as appropriate, in order to maximize margins or meet contract delivery requirements; and

        •
        marketing crude oil to refiners or other resellers.

              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:

       
      		 Year Ended December 31,
       
      		 2003
      		 2002
      		 2001
      		 2000
      		 1999
       
      		 (barrels in thousands)

      Lease gathering 437 410 348 262 265
      Bulk purchases(1) 90 68 46 28 138
        
      		 
      		 
      		 
      		 
       Total volumes 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 pipelinesLPG, as well as third party pipelines, trucksLPG fractionation and barges to transport the crude oil to market. We ownisomerization services.

      As of December 31, 2006, we employed a variety of owned or lease approximately 300 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 will be



      adjusted every three years based upon then existing market conditions. We are currently negotiating an amendment to the terms of the marketing agreement with PXP. See Item 13. "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.

              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 forleased long-term 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. See "Crude Oil Volatility; Counter-Cyclical Balance; Risk Management." 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 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 productsassets throughout the United States and Canada concentrated primarily in Washington, California, Kansas, Michigan, Texas, Montana, Nebraskathis segment, including:

      • approximately 30 million barrels of active, above-ground terminalling and storage facilities;
      • approximately 1.3 million barrels of active, underground terminalling and storage facilities; and
      • two fractionation plants and one isomerization unit with aggregate processing capacity of 26,400 barrels per day.
      At year-end 2006, the Canadian provincesPartnership was in the process of Alberta and Ontario. These activities include:

        •
        purchasing LPG (primarily propane and butane) from producers at gas plants and in bulk at major pipeline terminal points and storage locations;

        •
        transporting the LPG via common carrier pipelines, railcars and trucks to our own terminals and third party facilities for subsequent resale by them to retailers and other wholesale customers; and

        •
        exchanging product to other locations to maximize margins and/or to meet contract delivery requirements.

              We purchase LPG from numerous producers and have established long-term, broad-based relationships with LPG producers in our areasconstructing approximately 12.5 million barrels 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 pointsadditional above-ground terminalling 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 purchase only LPG for which we have a market,expect to place in service during 2007 and to structure2008.

      Our facilities segment also includes our sales contracts so that LPG spot price fluctuations do not materially affect the segment profit we receive. Marginequity earnings from our investment in PAA/Vulcan. At December 31, 2006, PAA/Vulcan owned and operated approximately 25.7 billion cubic feet of underground storage capacity and was constructing an additional 24 billion cubic feet of underground storage capacity which 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 creditexpected 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 onplaced in service in stages over 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. next three years.

      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.

        Terminalling and Storage Operations

              We own approximately 24.0 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 ofmonth-to-month and multi-year leases and processing arrangements. Revenues generated in this segment include (i) storage and throughput charges to third parties. Storage fees that are generated when we lease tank capacity to third parties. Terminallingand (ii) terminalling fees, also referred to asor throughput fees, that are generated when we receive crude oil from one connecting pipeline and redeliver crude oil to another connecting carriercarrier.

      Following is a tabular presentation of our active facilities segment assets and those under construction in volumes that allow the refinery to receive its crude oil onUnited States and Canada, grouped by product type:
      Facility
      Facility Description
      Capacity
      Crude oil and refined products
      Cushing
      		Crude oil terminalling and storage facility at the Cushing Interchange7.4 million barrels
      Eastern
      		Refined products terminals in Philadelphia, Pennsylvania and Paulsboro, New Jersey3.1 million barrels
      Kerrobert
      		Crude oil terminalling and storage facility located near Kerrobert, Saskatchewan1.7 million barrels
      LA Basin
      		Crude oil and refined products storage and pipeline distribution system in Los Angeles Basin9.0 million barrels
      Martinez and Richmond
      		Crude oil and refined products storage terminals in the San Francisco area4.5 million barrels
      Mobile and Ten Mile
      		Crude oil marine and storage terminals in Mobile, Alabama3.3 million barrels
      St. James
      		Crude oil terminal in Louisiana (Phase I)1.2 million barrels
      LPG
      Alto
      		Butane and propane salt cavern storage terminal in Michigan1.3 million barrels
      Arlington and Washougal
      		Transloading LPG terminals in Washington< 0.1 million barrels
      Claremont
      		Transloading LPG terminal in New Hampshire< 0.1 million barrels
      Cordova
      		Transloading LPG terminal in Illinois< 0.1 million barrels
      Fort Madison
      		Propane pipeline terminal in Iowa< 0.1 million barrels
      High Prairie
      		Fractionation facility in Alberta, producing butane, propane and stabilized condensate< 0.1 million barrels
      Kincheloe
      		Transloading LPG terminal in Michigan< 0.1 million barrels
      Schaefferstown
      		Refrigerated storage terminal in Pennsylvania0.5 million barrels


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      Facility
      Facility Description
      Capacity
      Shafter
      		Isomerization facility in California, producing isobutane, propane and stabilized condensate0.2 million barrels
      Tulsa
      		Propane pipeline terminal in Oklahoma< 0.1 million barrels
      Natural Gas
      Bluewater/Kimball
      		Natural gas storage facility in Michigan     25.7 Bcf (1)
      Under Construction
      Martinez
      		Expansion to crude oil and refined products terminal in California0.9 million barrels
      Mobile and Ten Mile
      		Expansion to crude oil terminal in Alabama0.6 million barrels
      Patoka
      		Crude oil storage and terminal facility in Patoka, Illinois2.6 million barrels
      Pier 400
      		Deepwater petroleum import terminal in the Port of Los AngelesUnder Development
      Pine Prairie
      		Natural gas storage facility in Louisiana24 Bcf (1)
      Cushing
      		Expansion to crude oil terminalling and storage facility at the Cushing Interchange3.4 million barrels
      St. James
      		Expansion to crude oil terminal in Louisiana (Phase I and II)5.0 million barrels
      (1) Our interest in these facilities is 50% of the capacity stated above
      Below is a ratable basis throughout a delivery period. Both terminalling and storage fees are generally earned from:

        •
        refiners and gatherers that segregate or custom blend crudes for refining feedstocks;

        •
        pipeline operators, refiners or traders that need segregated tankage for foreign cargoes;

        •
        traders who make or take delivery under NYMEX contracts; and

        •
        producers and resellers that seek to increase their marketing alternatives.

              The tankage that is used to supportdetailed description of 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). See "—Crude Oil Volatility; Counter-Cyclical Balance; Risk Management."

              Our mostmore significant terminalling and storage asset is our facilities segment assets.

      Major Facilities Assets
      Cushing Terminal
      Our Cushing Terminal is located at the Cushing Interchange. The Cushing Interchange, is one of the largestwet-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, with an initial tankage capacity of 2 million barrels, to capitalize on the crude oil supply and demand imbalance in the Midwest. The facility was designed to handle multiple grades of crude oil while minimizing the interface and enable deliveries to connecting carriers at their maximum rate. The facility also incorporates numerous environmental and operations safeguards that distinguish it from all other facilities at 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." InInterchange.
      Since 1999, we have completed our 1.1 million barrel Phase Ifive separate expansion project,phases, 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. The expansion increased the capacity of the Cushing Terminal to a total of approximately 5.37.4 million barrels. The Cushing Terminal now consists of fourteen100,000-barrel tanks, four150,000-barrel tanks and twelve twenty270,000-barrel tanks, all of which are used to store and terminal crude oil. In January 2004, we announced the commencement of our Phase IV expansion project, which will increase capacity by an incremental 1.1 million barrels, or approximately 20%. 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 30 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:

        •
        multiple, smaller tanks to facilitate simultaneous handling of multiple crude varieties in accordance with normal pipeline batch sizes;

        •
        dual header systems connecting most tanks to the main manifold system to facilitate efficient switching between crude grades with minimal contamination;

        •
        bottom drawn sumps that enable each tank to be efficiently drained down to minimal remaining volumes to minimize crude oil contamination and maintain crude oil integrity during changes of service;

        •
        mixer(s) on each tank to facilitate blending crude oil grades to refinery specifications; and

        •
        a manifold and pump system that allows for receipts and deliveries with connecting carriers at their maximum operating capacity.

              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 aone year old to approximately 1113 years old and thewith an average age is approximately 5.7 years old.of six years. In contrast, we estimate that the average age of the approximately 21 million barrels of remaining tanks in Cushing owned by third parties is in excess of 40 years.

      In September 2006, we announced our Phase VI expansion of our Cushing Terminal facility. Under the average age isPhase VI expansion, we will construct approximately 50 years and of that, approximately 93.4 million barrels hasof additional tankage. The Phase VI project will expand the total capacity of the facility to 10.8 million barrels and, including manifold modifications, is expected to cost approximately $48 million of which $27 million is the estimated remaining project cost to be incurred in 2007. We estimate that the new tankage will become operational during the fourth quarter of 2007. The expansion is supported by multi-year lease agreements.
      Eastern Terminals
      We own three refined product terminals in the Philadelphia, Pennsylvania area: a 0.9 million barrel terminal in North Philadelphia, a 0.6 million barrel terminal in South Philadelphia and a 1.6 million barrel terminal in Paulsboro, New Jersey. Our Philadelphia area terminals have 40 storage tanks with combined storage capacity of 3.1 million barrels. The terminals have 20 truck loading lanes, two barge docks and a ship dock. The Philadelphia

      19

      area terminals provide services and products to all of the refiners in the Philadelphia harbor. The North Philadelphia and Paulsboro terminals have dock facilities that can load approximately 10,000 to 12,000 barrels per hour of refined products and black oils. The Philadelphia area terminals also receive products from connecting pipelines and offer truck loading services, barge cleaning and tug fuel services.
      At our Philadelphia area terminals, we have completed an average ageethanol expansion project which enabled us to increase our ethanol handling and blending capabilities as well as increase our marine receipt capabilities. We plan to expand our Paulsboro facility by approximately 1.0 million barrels consisting of over 70 years. eight tanks ranging from 50,000 barrels to 150,000 barrels. This expansion is in the permitting stage and is scheduled to be completed in 2008 at an estimated cost of $31 million, of which approximately $20 million is scheduled to be spent in 2007.
      Kerrobert
      We believe that provides usown a crude oil and condensate storage and terminalling facility located near Kerrobert, Saskatchewan with a competitive advantage overstorage capacity of approximately 1.7 million barrels. The facility is connected to our competitors.Manito and Cactus Lake pipeline systems. In 2006, we increased the storage capacity at our Kerrobert facility by 900,000 barrels of tankage, bringing the total storage capacity to 1.7 million barrels. The cost of the expansion is estimated to be approximately $47 million, of which approximately $14 million is the estimated remaining project cost to be incurred in 2007.
      Los Angeles Area Storage and Distribution System
      We own four crude oil and refined product storage facilities in the Los Angeles area with a total of 9.0 million barrels of storage capacity and a distribution pipeline system of approximately 70 miles of pipeline in the Los Angeles Basin. The storage facility includes 34 storage tanks. Approximately 7.0 million barrels of the storage capacity are in active commercial service, 0.5 million barrels are used primarily for throughput to other storage tanks and do not generate revenue independently, approximately 1.2 million barrels are idle but could be reconditioned and brought into service and approximately 0.3 million barrels are in displacement oil service. We refurbished and placed in service 0.3 million barrels of black oil storage capacity in the third quarter of 2006 and expect to complete refurbishing an additional 0.3 million barrels of black oil storage in the first quarter of 2007. We are also making infrastructure changes to increase pumping capacity and improve operating efficiencies, which we expect to complete in 2007. We use the Los Angeles area storage and distribution system to service the storage and distribution needs of the refining, pipeline and marine terminal industries in the Los Angeles Basin. In addition, the Los Angeles area system has 17 storage tanks with a total of approximately 0.4 million barrels of storage capacity that are out of service. We are in the process of completing refurbishments and infrastructure changes at this facility. The Los Angeles area system’s pipeline distribution assets connect its storage assets with major refineries, our Line 2000 pipeline, and third-party pipelines and marine terminals in the Los Angeles Basin. The system is capable of loading and off-loading marine shipments at a rate of 25,000 barrels per hour and transporting the product directly to or from certain refineries, other pipelines or its storage facilities. In addition, we believecan deliver crude oil and feedstocks from our storage facilities to the refineries served by this system at rates of up to 6,000 barrels per hour.
      Martinez and Richmond Terminals
      We own two terminals in the San Francisco, California area: a 3.9 million barrel terminal at Martinez (which provides refined product and crude oil service) and a 0.6 million barrel terminal at Richmond (which provides refined product service). Our San Francisco area terminals currently have 49 storage tanks with 4.5 million barrels of combined storage capacity that are connected to area refineries through a network of owned and third-party pipelines that carry crude oil and refined products to and from area refineries. The terminals have dock facilities that can load between approximately 4,000 and 10,000 barrels per hour of refined products. There is also a rail spur at the Richmond terminal that is able to receive products by train.
      We recently added 450,000 barrels of storage capacity at the Martinez terminal and we are well positionedconstructing an additional 850,000 barrels of storage capacity for completion in 2007 at a remaining estimated project cost of approximately $27 million.


      20

      Mobile and Ten Mile Terminal
      We have a marine terminal in Mobile, Alabama (the “Mobile Terminal”) that consists of eighteen tanks ranging in size from 10,000 barrels to accommodate225,000 barrels, with current useable capacity of 1.5 million barrels. Approximately 1.8 million barrels of additional storage capacity is available at our nearby Ten Mile Facility through a 36” pipeline connecting the two facilities. In 2006, we started construction of replacement tankage that maya 600,000 barrel tank at the Ten Mile Facility. The cost for this tank is expected to be requiredapproximately $6.4 million of which $5.8 million is the estimated remaining project cost to be incurred in 2007. The new tank is expected to be in service in the second quarter of 2007.
      The Mobile Terminal is equipped with a ship/tanker dock, barge dock, truck-unloading facilities and various third party connections for crude oil movements to area refiners. Additionally, the Mobile Terminal serves as a resultsource for imports of foreign crude oil to PADD II refiners through our Mississippi/Alabama pipeline system, which connects to the impositionCapline System at our station in Liberty, Mississippi.
      St. James Terminal
      In 2005, we began construction 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 only3.5 million barrel crude oil terminal at the Cushing Interchange equipped with aboveground pipelines. LikeSt. James crude oil interchange in Louisiana, which is one of the pipeline systemsthree most liquid crude oil interchanges in the United States. In the first phase of construction, we operate, the Cushing Terminal is operated by a computer system designedplan to monitor real-time operational data and each tank is cathodically protected. In addition, each tank is equippedbuild seven tanks ranging from 210,000 barrels to 670,000 barrels with an audibleaggregate shell capacity of approximately 3.5 million barrels. At December 31, 2006, 1.2 million barrels of capacity were in service. The remaining capacity of Phase I is expected to be operational during the first quarter of 2007. The estimated total cost of Phase I is estimated to be approximately $105 million, of which $17.3 million is the estimated remaining project cost to be incurred in 2007. The facility will also include a manifold and visual high-level alarmheader system that will allow for receipts and deliveries with connecting pipelines at their maximum operating capacity.

      Under the Phase II project, we will construct approximately 2.7 million barrels of additional tankage at the facility. The Phase II project will expand the total capacity of the facility to prevent overflows;6.2 million barrels and is expected to cost approximately $64 million of which $43 million is the estimated project cost to be incurred in 2007. We estimate that the Phase II tankage will become operational during the first quarter of 2008.
      Shafter
      Our Shafter facility (acquired through the Andrews acquisition) provides isomerization and fractionation services to producers and customers of natural gas liquids (“NGLs”) throughout the Western United States. The primary assets consist of 200,000 barrels of NGL storage, a double seal floating roof designedprocessing facility with butane isomerization capacity of 14,000 barrels per day and NGL fractionation capacity of 9,600 barrels per day, and office facilities in California.
      Patoka Terminal
      In December 2006, we announced that we will build a 2.6 million barrel crude oil storage and terminal facility at the Patoka interchange in Patoka, Illinois. We anticipate that the new facility will become operational during the second half of 2008 for a total cost of approximately $77 million, including land costs. We expect to minimize air emissions and preventincur approximately half of the possible accumulation of potentially flammable gases between fluid levelscost in 2007 and the roofremainder in 2008. Patoka is a growing regional hub with access to domestic and foreign crude oil volumes moving north on the Capline system as well as Canadian barrels moving south. This project will have the ability to be expanded should market conditions warrant.
      Pier 400
      We are in the process of developing a deepwater petroleum import terminal at Pier 400 and Terminal Island in the Port of Los Angeles to handle marine receipts of crude oil and refinery feedstocks. As currently envisioned, the project would include a deep water berth, high capacity transfer infrastructure and storage tanks, with a pipeline distribution system that will connect to various customers.
      We have entered into agreements with ConocoPhillips and two subsidiaries of Valero Energy Corporation that provide long-term customer commitments to off-load a total of 140,000 bpd of crude oil at the Pier 400 dock. The ConocoPhillips and Valero agreements are subject to satisfaction of various conditions, such as the achievement of


      21

      various progress milestones, financing, continued economic viability, and completion of other ancillary agreements related to the project. We are negotiating similar long-term off-loading agreements with other potential customers.
      We have failed to meet certain project milestone dates set forth in our Valero agreements, and we are likely to miss other project milestones that are approaching under these agreements. Valero has not given any indication that it will seek to terminate such agreements. We expect that ongoing negotiations with Valero to extend the milestone dates will be successful and that the Valero agreements will remain in effect.
      In January 2007, we completed an updated cost estimate for the project. We are estimating that Pier 400, when completed, will cost approximately $360 million, which is subject to change depending on various factors, including: (i) the final scope of the tank;project and a foam dispersal system that,the requirements imposed through the permitting process and (ii) changes in construction costs. This cost estimate assumes the construction of 4.0 million barrels of storage. We are in the eventprocess of securing the environmental and other permits that will be required for the Pier 400 project from a variety of governmental agencies, including the Board of Harbor Commissioners, the South Coast Air Quality Management District, various agencies of the City of Los Angeles, the Los Angeles City Council and the U.S. Army Corps of Engineers. We expect to have the necessary permits in the first quarter of 2008. Final construction of the Pier 400 project is subject to the completion of a fire, is fed byland lease (that will include a fully-automated fire water distribution network.



              The following table sets forth throughput volumes for our terminallingdock construction agreement) with the Port of Los Angeles, receipt of environmental and storage operationsother approvals, securing additional customer commitments, updating engineering and quantityproject cost estimates, ongoing feasibility evaluation, and financing. Subject to timely receipt of tankage leased to third parties for our Cushing Terminal forapprovals, we expect construction of the past five years.

      Pier 400 terminal may be completed and the facility placed in service in 2009 or 2010.
       
      		 Year Ended December 31,
       
      		 2003
      		 2002
      		 2001
      		 2000
      		 1999
       
      		 (barrels in thousands)

      Throughput volumes (average daily volumes) 208 110 94 59 72
      Storage leased to third parties (average monthly volumes)(1) 1,165 1,067 2,136 1,437 1,743
      (1)
      The level of tankage at Cushing that we allocate for our arbitrage activities (and therefore is not available for lease to third parties) varies throughout crude oil price cycles.

      LPG Storage Facilities and Terminals
      We also own anthe following LPG storage facility located in Alto, Michigan, which is approximately 20 miles southeast of Grand Rapids. The Alto facility was acquired from Ohio-Northwest Development Inc. in 2003facilities and is capable of storing over 38 million gallons of LPG. terminals:
      • Storage facilities with the capability of storing approximately 1.7 million barrels of product;
      • Pipeline terminals consisting of (i) a130-mile pipeline and terminal that is capable of storing 17,000 barrels of propane, and (ii) a facility that can store 7,000 barrels of propane where product is shipped out via truck; and
      • Transloading facilities where product is delivered by rail car and shipped out via truck, with approximately 24,000 barrels of operational storage capacity.
      We believe the facilitythese facilities will further support the expansion of our LPG business in Canada and the northern tier of the U.S. as we combine the facility'sfacilities’ existing fee-based storage business with our wholesale propane marketing expertise. In addition, there may be opportunities to expand this facilitythese facilities as LPG markets continue to develop in the region.

      Natural Gas Storage Assets
      We believe strategically located natural gas storage facilities with multi-cycle injection and withdrawal capabilities and access to critical transportation infrastructure will play an increasingly important role in balancing the markets and ensuring reliable delivery of natural gas to the customer during peak demand periods. We believe that our expertise in hydrocarbon storage, our strategically located assets, our financial strength and our commercial experience will enable us to play a meaningful role in meeting the challenges and capitalizing on the opportunities associated with the evolution of the U.S. natural gas storage markets.
      Bluewater.  The Bluewater gas storage facility, which is located in Michigan, is a depleted reservoir facility with an approximate 23 Bcf of capacity and is also strategically positioned. In April 2006, PAA/Vulcan acquired the Kimball gas storage facility and connected this 2.7 Bcf facility to the Bluewater facility. Natural gas storage facilities in the northern tier of the U.S. are traditionally used to meet seasonal demand and are typically cycled once or twice during a given year. Natural gas is injected during the summer months in order to provide for adequate deliverability during the peak demand winter months. Michigan is a very active market for natural gas storage as it meets nearly 75% of its peak winter demand from storage withdrawals. The Bluewater facility has direct interconnects to four major pipelines and has indirect access to another four pipelines as well as to Dawn, a major natural gas market hub in Canada.


      22

      Pine Prairie.  The Pine Prairie facility is expected to become partially operational in 2007 and fully operational in 2009, and we believe it is well positioned to benefit from evolving market dynamics. The facility is located near Gulf Coast supply sources and near the existing Lake Charles LNG terminal, which is the largest LNG import facility in the United States. When completed, the Pine Prairie facility is expected to be a 24 Bcf salt cavern storage facility designed for high deliverability operating characteristics and multi-cycle capabilities. The initial phase of the facility will consist of three storage caverns with working capacity of eight Bcf per cavern and an extensive header system. Drilling operations on two of the three cavern wells is complete and drilling operations on the third cavern well commenced in late December 2006. Leaching operations on the first cavern well began in November 2006, construction of the gas handling and compression facilities began in December 2006 and construction on the pipeline interconnects began during January 2007. The site is located approximately 50 miles from the Henry Hub, the delivery point for NYMEX natural gas futures contracts, and is currently intended to interconnect with seven major pipelines serving the Midwest and the East Coast. Three additional pipelines are also located in the vicinity and offer the potential for future interconnects. We believe the facility’s operating characteristics and strategic location position Pine Prairie to support the commercial functions of power generators, pipelines, utilities, energy merchants and LNG re-gasification terminal operators and provide potential customers with superior flexibility in managing their price and volumetric risk and balancing their natural gas requirements. In January 2007, an additional 240 acres of land were purchased adjacent to the Pine Prairie project to support future expansion activities.
      Marketing
      Our marketing segment operations generally consist of the following merchant activities:
      • the purchase of U.S. and Canadian crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities, as well as the purchase of foreign cargoes at their load port and various other locations in transit;
      • the storage of inventory during contango market conditions;
      • the purchase of refined products and LPG from producers, refiners and other marketers;
      • the resale or exchange of crude oil, refined products and LPG at various points along the distribution chain to refiners or other resellers to maximize profits; and
      • arranging for the transportation of crude oil, refined products and LPG on trucks, barges, railcars, pipelines and ocean-going vessels to our terminals and third-party terminals.
      Our marketing activities are designed to produce a stable baseline of results in a variety of market conditions, while at the same time providing upside exposure to opportunities inherent in volatile market conditions. These activities utilize storage facilities at major interchange and terminalling locations and various hedging strategies to reduce the negative impact of market volatility and provide counter-cyclical balance. 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).
      In addition to substantial working inventories and working capital associated with its merchant activities, the marketing segment also employs significant volumes of crude oil and LPG as linefill or minimum inventory requirements under service arrangements with transportation carriers and terminalling providers. The marketing segment also employs trucks, trailers, barges, railcars and leased storage.
      As of December 31, 2006, the marketing segment owned crude oil and LPG classified as long-term assets and a variety of owned or leased long-term physical assets throughout the United States and Canada, including:
      • 7.9 million barrels of crude oil and LPG linefill in pipelines owned by the Partnership;
      • 1.5 million barrels of crude oil and LPG linefill in pipelines owned by third parties;
      • 500 trucks and 600 trailers; and
      • 1,300 railcars.


      23

      In connection with its operations, the marketing segment secures transportation and facilities services from the Partnership’s other two segments as well as third-party service providers undermonth-to-month and multi-year arrangements. Inter-segment transportation service rates are based on posted tariffs for pipeline transportation services. Facilities segment services are also obtained at rates consistent with rates charged to third parties for similar services; however, certain terminalling and storage rates are discounted to our marketing segment to reflect the fact that these services may be canceled on short notice to enable the facilities segment to provide services to third parties.
      We purchase crude oil and LPG from multiple producers and believe that we generally have established long-term, broad-based relationships with the crude oil and LPG producers in our areas of operations. Marketing activities involve relatively large volumes of transactions, often with lower margins than transportation and facilities operations. Marketing activities for LPG typically consist of smaller volumes per transaction relative to crude oil.
      The following table shows the average daily volume of our lease gathering, LPG sales and waterborne foreign crude imported for the past five years:
                           
        Year Ended December 31, 
        2006  2005  2004  2003  2002 
        (Barrels in thousands) 
       
      Crude oil lease gathering  650   610   589   437   410 
      LPG sales  70   56   48   38   35 
      Waterborne foreign crude imported  63   59   12   —   — 
                           
      Total volumes per day  783   725   649   475   445 
                           
      Crude Oil and LPG Purchases.  We purchase crude oil in North America from producers under contracts, the majority of which range in term from athirty-day evergreen to three-year term. We utilize our truck fleet and gathering pipelines as well as third party pipelines, trucks and barges to transport the crude oil to market. In addition, we purchase foreign crude oil. Under these contracts we may purchase crude oil upon delivery in the U.S. or we may purchase crude oil in foreign locations and transport crude oil on third-party tankers.
      We purchase LPG from producers, refiners, and other LPG marketing companies under contracts that range from immediate delivery to one year in term. We utilize leased railcars and third party tank truck or pipelines to transport LPG.
      In addition to purchasing crude oil from producers, we purchase both domestic and foreign crude oil in bulk at major pipeline terminal locations and barge facilities. 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 crude oil and LPG in bulk when we believe additional opportunities exist to realize margins further downstream in the crude oil or 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.
      Crude Oil and LPG Sales.  The marketing of crude oil and LPG is complex and requires current detailed knowledge of crude oil and LPG 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, location of customers, various modes and availability of transportation facilities and timing and costs (including storage) involved in delivering crude oil and LPG 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. The majority of these contracts are at market prices and have terms ranging from one month to three years. We sell LPG primarily to retailers and refiners, and limited volumes to other marketers. We establish a margin for crude oil and LPG we purchase by sales for physical delivery to third party users, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX, IntercontinentalExchange (“ICE”) orover-the-counter. Through these transactions, we seek to maintain a


      24

      position that is substantially balanced between crude oil and LPG 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 and LPG-related futures contracts as hedging devices.
      Crude Oil and LPG 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, type or volume of crude oil or LPG that more closely matches our physical delivery requirement, location or the preferences of our customers, we exchange physical crude oil or LPG, as appropriate, 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 or LPG that differs in terms of geographic location, grade of crude oil or type of LPG, or physical delivery schedule from crude oil or LPG we have available for sale. Generally, we enter into exchanges to acquire crude oil or LPG 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. See Note 2 to our Consolidated Financial Statements.
      Credit.  Our merchant activities involve the purchase of crude oil and LPG for resale and require significant extensions of credit by our suppliers of crude oil and LPG. In order to assure our ability to perform our obligations under crude oil purchase agreements, various credit arrangements are negotiated with our suppliers. These arrangements include open lines of credit directly with us and, to a lesser extent, standby letters of credit issued under our senior unsecured revolving credit facility.
      When we sell crude oil and LPG, 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 crude oil 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 approximately $2 per barrel to 100% of their contracted amounts. Generally, sales of LPG are settled within 30 days of the date of invoice.
      Crude Oil Volatility; Counter-Cyclical Balance; Risk Management

      Crude oil commodity prices have historically been very volatile and cyclical, withcyclical. For example, NYMEX WTI crude oil benchmark prices ranginghave ranged from asa high as $40.00of over $78 per barrel (July 2006) to asa low as $10.00of $10 per barrel (March 1986) over the last 1420 years. Segment profit from terminalling and storageour facilities 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 and LPG at a priceprices in excess of our aggregate cost. Although margins may be affected during transitional periods, theseour crude oil marketing 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-relatedmarket related indices.

      During periods when supply exceeds the demand for crude oil in the near term, 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


      25

      has a generally negative impact on marketingour lease gathering margins, but is favorable to our commercial strategies that are associated with storage tankage leased from the facilities segment or from third parties. Those who control 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 marketingour lease gathering 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.segment. When the market is in contango, we will use our tankage to improve our lease 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 marketinglease gathering margins provide an offset to this reduced cash flow. We believe that the combination of our terminalling and storagelease gathering activities and gathering and marketing activitiesthe commercial strategies used with our tankage provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow. In addition, we supplement the counter-cyclical balance of our asset base with derivative hedging activities in an effort to maintain a base level of margin irrespective of crude oil market conditions and, in certain circumstances, to realize incremental margin during volatile market conditions. References to counter-cyclical balance elsewhere in this report are referring to this relationship between our terminalling and storagefacilities 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 and ICE futures contracts and derivatives, have become increasingly important in creating and maintaining margins. Such hedging techniques require significant resources dedicatedIn order to managing these positions.hedge margins involving our physical assets and manage risks associated with our various commodity purchase and sale obligations (mainly relating to crude oil) and, in certain circumstances, to realize incremental margin during volatile market conditions, we use derivative instruments, including regulated futures and options transactions, as well asover-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. Our risk management policies and procedures are designed to monitor both NYMEX, ICE andover-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 risk management function also approves all new risk management strategies through a formal process. With the exception of the controlled trading program discussed below, 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.

      Our policy is generally to purchase only crude oilproduct 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 crude oil trading program discussed below, we do not acquire and hold crude oilphysical inventory, futures contracts or other derivative products for the purpose of speculating on crude oilcommodity price changes that mightas these activities could expose us to indeterminablesignificant losses.

              While

      Although 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


      26

      for our core business, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil and an aggregate of 250,000 barrels of LPG.oil. This controlled trading activity is monitored independently by our risk management function and must take place within predefined limits and authorizations.

              In order Such amounts exclude unhedged working inventory volumes that remain relatively constant and are subject 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 hopeslower 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.

      cost or market adjustments.

      Although the intent of our risk-management strategies is to hedge our margin, not all of our derivatives qualify for hedge accounting. This could be the result of a derivative that is an effective element of our risk management strategy that may not be sufficiently effective to qualify for hedge accounting or a derivative that is disallowed hedge accounting treatment under SFAS 133 due to the uncertainty of physical delivery. Additionally, certain elements of our risk management strategies such as the time value of options do not qualify for hedge accounting under SFAS 133 whether effective or not. In such instances, changes in the fair values of these derivatives that do not qualify or are excluded from hedge accounting will receivemark-to-market treatment in current earnings, and result in greater potential for earnings volatility than in the past. This accounting treatment is discussed further in Note 2 "Summary of Significant Accounting Policies" in the "Notes to the Consolidated Financial Statements."

      volatility.

      Geographic Data; Financial Information about Segments

      See Note 15 "Operating Segments"to our Consolidated Financial Statements.
      Customers
      Marathon Petroleum Company, LLC (“Marathon”) accounted for 14%, 11% and 10% of our revenues for each of the three years in the "Notesperiod ended December 31, 2006. Valero Marketing & Supply Company (“Valero”) accounted for 10% of our revenues for the year ended December 31, 2006. BP Oil Supply accounted for 14% and 10% of our revenues for the years ended December 31, 2005 and 2004, respectively. No other customers accounted for 10% or more of our revenues during any of the three years. The majority of revenues from Marathon, Valero and BP Oil Supply pertain to our marketing operations. We believe that the Consolidated Financial Statements."


      Customers

              See Note 9 "Major Customersloss 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 Concentration of Credit Risk" in the "Notes to the Consolidated Financial Statements."

      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 acquiringrights-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-partythird 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 also face intense competition in our gathering, marketing terminallingservices and storage operations.facilities services. 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 laws and regulations. We estimate that we are subject to regulatory oversight by over 70numerous 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, related businesses and individual participants. The failure to comply with such ruleslaws 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 myriadFollowing is a discussion of complex federal, state, provincialcertain laws and local regulations that may affect us, directly or indirectly,affecting us. However, you should not rely on the followingsuch discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.


      27

      Pipeline and Storage Regulation

      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"Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration with respect to the design, installation, testing, construction, operation, replacement and management of pipeline and tank facilities. Comparable regulation exists in some states in which we conduct intrastate common carrier or private pipeline operations. Regulation in Canada is under the National Energy Board (“NEB”) and provincial agencies. 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 privateU.S. Federal pipeline operations.

              Pipeline safety issues are currently receiving significant attention in various political and administrative arenas at both the state and federal levels. For example, recent federal rule changesrules also require pipeline operators to: (1)to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities, and (2) establishfacilities.

      In 2001, the DOT adopted the initial pipeline integrity management programs. In particular, during 2000, the DOT adopted new regulations requiringrule, which required operators of interstatejurisdictional pipelines transporting hazardous liquids 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“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 ourIn December 2003, the DOT issued a final rule requiring natural gas pipeline operators to develop similar integrity management programs for gas transmission pipelines are located in high consequence areas. TheSegments of our pipelines transporting hazardous liquidsand/or natural gas in high consequence areas are subject to these DOT rule requiresrules 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, including enhanced damage prevention programs, corrosion control program improvements, leak detection system enhancements, installation of emergency flow restricting devices, and emergency preparedness improvements.pipelines. The DOT rulerules also requiresrequire us to evaluate and, as necessary, improve our management and analysis processes for integrating available integrity-relatedintegrity 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$8.2 million in 2003.2006, $4.7 million in 2005 and approximately $5 million in 2004. Based on currently available information, weour preliminary estimate that the costs to implement and carryout this program will befor 2007 is approximately $1.8 million in 2004.$10.5 million. The relative increase in program cost for 2004over the last few years is primarily attributable to pipeline segments acquired in 2003, thatrecent years (including the Pacific and Link assets), which are subject to the new regulation and which were scheduled for assessment in 2004. Theserules. Certain of these costs are recurring in nature and thus will also impact future periods. We will continue to refine our estimates as information from our assessments is collected. 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, regulations imposed infuture regulation.

      In September 2006, the future. We will continueDOT published a Notice of Proposed Rulemaking (“NPRM”) that proposed to refine our estimates as information from initial assessments is collected.

              The DOT is currently considering expanding the scope of its pipeline regulation to includeregulate certain hazardous liquid gathering and low stress pipeline systems that are not currently subject to regulation. This expanded scope would likelyOn December 6, 2006, the Congress passed, and on December 29, 2006 President Bush signed into law, H.R. 5782, the “Pipeline Inspection, Protection, Enforcement and Safety Act of 2006” (2006 Pipeline Safety Act), which reauthorizes and amends the DOT’s pipeline safety programs. Included in the 2006 Pipeline Safety Act is a provision eliminating the regulatory exemption for hazardous liquid pipelines operated at low stress, which was one of the focal points of the September 2006 NPRM. The Act requires DOT to issue regulations by December 31, 2007 for those hazardous liquid low stress pipelines now subject to regulation pursuant to the 2006 Pipeline Safety Act. Regulations issued by December 31, 2007 with respect to hazardous liquid low stress pipelines as well as any future regulation of hazardous liquid gathering lines could include requirements for 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 weWe do not currently know what, if any, impact thisthese developments will have on our operating expenses. However, weexpenses and, thus, cannot assure youprovide any assurances that future costs related to the potentialthese programs will not be material.

      In addition to performing DOT-mandated pipeline integrity evaluations, during 2006, we expanded an internal review process started in 2005 in which we are reviewing various aspects of our pipeline and gathering systems that are not subject to the DOT pipeline integrity management rule. The purpose of this process is to review the surrounding environment, condition and operating history of these pipelines and gathering assets to determine if such assets warrant additional investment or replacement. Accordingly, we could be required (as a result of


      28

      additional DOT regulation) or we may elect (as a result of our own internal initiatives) 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 63%79% of our 24.060 million barrels)barrels are subject to DOT jurisdiction). API 653 requires regularly scheduled inspection and repair of tanks remaining in service. Full compliance is required byin 2009. We have commenced our compliance activitiesCosts associated with this program were approximately $6.8 million, $4.4 million and based$3 million in 2006, 2005 and 2004, respectively. Based on currently available information, we estimate thatanticipate we will spend an approximate average of $3$15.7 million per year from 2007 through 2009 (approximately $2 million in 2004) in connection with API 653 compliance activities. Such amounts incorporateIn some cases, we may take storage tanks out of service if we believe the costs associated withcost of upgrades will exceed the assets acquired in 2003.value of the storage tanks or construct replacement tankage at a more optimal location. We will continue to refine our estimates as information from initialour 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 provide any assurance that these security measures would fully protect our facilities from a concentrated attack. See “— Operational Hazards and Insurance.”
      In Canada, the NEB and provincial agencies such as the Alberta Energy and Utilities Board and Saskatchewan Industry and Resources regulate the construction, alteration, inspection and repair of crude oil storage tanks. We expect to incur costs under laws and regulations related to pipeline and storage tank integrity, such as operator competency programs, regulatory upgrades to our operating and maintenance systems and environmental upgrades of buried sump tanks. We spent approximately $4.5 million in 2006, $4.9 million in 2005 and $4.1 million in 2004 on compliance activities. Our preliminary estimate for 2007 is approximately $6.9 million. Certain of 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. 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.
      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 uncertainthe regulatory standards in the U.S. and could vary materially from our current projections.

              Since the terrorist attacks of September 11, 2001, the United States Government has issued numerous warnings that energy assets (including our nation's pipeline infrastructure) may be future targets of terrorist organizations. These developments expose our operations and assets to increased risks. We have instituted security measures and procedures in conformity with DOT guidance. We will institute, as appropriate, additional security measures or procedures indicated by the DOT or the

      Canada.


      Transportation Safety Administration (an agency of the Department of Homeland Security, which has assumed responsibility from the DOT). We cannot assure you that these or any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not. See "—Operational Hazards and Insurance."

      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 includesinclude both crude oil as well aspipelines and refined product and petrochemicalproducts 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 state regulatory bodies.

      bodies, including the California Public Utility Commission, which prohibits certain of our subsidiaries from acting as guarantors of our senior notes and credit facilities. See Note 12 to our Consolidated Financial Statements.

      Canadian Regulation.  Our Canadian pipeline assets are subject to regulation by the NEB and by provincial agencies.authorities, such as the Alberta Energy and Utilities Board. With respect to a pipeline over which it has jurisdiction, each of these agenciesthe relevant regulatory authority 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


      29

      relevant regulatory agencyauthority determines that the applicable terms and conditions of service are not just and reasonable, the agencyregulatory authority can amend the offending provisions of an existing transportation contract.

      impose conditions it considers appropriate.

      Energy Policy Act of 1992 and Subsequent Developments.  In October 1992, Congress passed the Energy Policy Act of 1992 (“EPAct”), which among other things, required the FERC to issue rules 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. Specifically, the indexing methodology allows a pipeline to increase its rates annually by a percentage equal to the change in the producer price index for finished goods (“PPI-FG”) plus 1.3% to the new ceiling level. 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'spipeline’s increase in costs. If the PPI-FG falls and the indexing methodology results in a reduced ceiling level that is lower than a pipeline'spipeline’s filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling.ceiling unless doing so would reduce a rate “grandfathered” by EPAct (see below) below the grandfathered level. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, retainedcost-of-service ratemaking, market-basedmarket based rates, and settlement as alternatives to the indexing approach, which alternatives may be used in certain specified circumstances. The Energy Policy ActFERC’s indexing methodology is subject to review every five years; the current methodology is expected to remain in place through June 30, 2011. If the FERC continues its policy of using the PPI-FG plus 1.3%, changes in that index might not fully reflect actual increases in the costs associated with the pipelines subject to indexing, thus hampering our ability to recover cost increases.
      The EPAct deemed petroleum pipeline rates in effect for the365-day period ending on the date of enactment of the Energy Policy Act orEPAct that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the that365-day period to be just and reasonable under the Interstate Commerce Act. Generally, complaints against such "grandfathered"“grandfathered” rates may only be pursued if the complainant can show either that a substantial change has occurred since the enactment of EPAct in either the economic circumstances of the oil pipeline, that were a basis for the rate or in the nature of the services has occurred since enactment orprovided, that were a basis for the rate. EPAct places no such limit on challenges to a provision of thean oil pipeline tariff isas unduly discriminatory or preferential.

              In a proceeding involving Lakehead Pipe Line Company, Limited Partnership (Opinion Nos. 397

      On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) issued its opinion inBP West Coast Products, LLC v. FERC, which upheld FERC’s determination that certain rates of an interstate petroleum products pipeline, SFPP, L.P. (“SFPP”), were grandfathered rates under EPAct and 397-A),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 theLakeheadpolicy, under which the FERC concluded that there should not beallowed a corporateregulated entity organized as a master limited partnership (or “MLP”) to include in itscost-of-service an income tax allowance built intoto the extent that entity’s unitholders were corporations subject to income tax. On May 4, 2005, the FERC adopted a petroleum pipeline'spolicy statement in DocketNo. PL05-5 (“Policy Statement”), stating that it would permit entities owning public utility assets, including oil pipelines, to include an income tax allowance in such utilities’cost-of-service rates to reflect the actual or potential income tax liability attributable to noncorporate partners because noncorporate partners, unlike corporate partners, do not paytheir public utility income, regardless of the form of ownership. Pursuant to the Policy Statement, a corporate income tax. Additionally, on January 13, 1999, the FERC issued Opinion No. 435 in a proceeding involving SFPP, L.P., which, among other things, affirmed Opinion No. 397's determination that there should not be a corporatetax pass-through entity seeking such an income tax allowance built intowould have to establish that its partners or members have an actual or potential income tax obligation on the entity’s public utility income. Whether a petroleum pipeline's ratespipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on acase-by-case basis. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, such as MLPs, it still entails rate risk due to reflect income attributablethecase-by-case review requirement. The new tax allowance policy has been appealed to



      noncorporate partners. Petitions for review of Opinion No. 435 and subsequent FERC opinions in that case are pending before the D.C. Circuit CourtCircuit. As a result, the ultimate outcome of Appeals.

              In anotherthese proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service. FERC proceeding involving SFPP, L.P., certain shippers are challenging grandfatheredcontinues to refine its tax allowance policy incase-by-case reviews; how the policy statement on income tax allowances is applied in practice to pipelines owned by MLPs, and whether it is ultimately upheld or modified on judicial review, could affect the rates onof FERC regulated pipelines.

      Additionally, the basis ofcriteria for establishing substantially changed circumstances sinceunder EPAct, among other issues, are currently under review by the passageD.C. Circuit. Oral argument was held on December 12, 2006, but the court


      30

      has not yet issued an opinion. We have no way of the Energy Policy Act. The ultimate disposition of this challenge may define "substantial change" in such a way as to make grandfathered rates more vulnerable to challenge than has historically been the case. We are uncertainknowing what effect, if any, an unfavorable determination inaction by the FERC proceedingand/or the D.C. Circuit on this issue and others might have on our grandfathered tariffs.

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

        with one or more shippers.

      Trucking Regulation

      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.DOT. 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"(“OSHA”), with respect to our trucking operations.

      Our trucking assets in Canada are subject to regulation by both federal and provincial transportation 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, equipmenttraining and certification, facility inspection, hazardous materialsreporting and safety.

      Cross-BorderCross Border Regulation

      As a result of our Canadian acquisitions and cross-bordercross border activities, including importation of crude oil into the United States, we are subject to regulatory mattersa variety of legal requirements pertaining to such activities including export licenses,export/import license requirements, tariffs, Canadian and U.S. customs and tax issuestaxes and requirements relating to toxic substance certifications. Regulationssubstances. U.S. legal requirements relating to these activities include regulations adopted pursuant to 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 or failure to provide certifications relating to toxic substances could result in the imposition of significant administrative, civil and criminal penalties. Furthermore, the failure to comply with U.S., Canadian, state, provincial and local tax requirements could lead to the imposition of additional taxes, interest and penalties. See Item 3. "Legal Proceedings."
      Natural Gas Storage Regulation
      Interstate Regulation.  The interstate storage facilities in which we have an investment are or will be subject to rate regulation by the FERC under the Natural Gas Act. The Natural Gas Act requires that tariff rates for gas storage facilities be just and reasonable and non-discriminatory. The FERC has authority to regulate rates and charges for natural gas transported and stored for U.S. interstate commerce or sold by a natural gas company via interstate commerce for resale. The FERC has granted market-based rate authority under its existing regulations to PAA/Vulcan’s Pine Prairie Energy Center, which is under construction in Louisiana, and to its Bluewater gas storage facility.
      The FERC also has authority over the construction and operation of U.S. transportation and storage facilities and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. Absent an exemption granted by the FERC, FERC’s Standard of Conduct regulations restricted access to U.S. interstate natural gas storage customer data by marketing and other energy affiliates, and placed certain conditions on services provided by the U.S. storage facility operators to their affiliated gas marketing entities. Pine Prairie Energy Center elected to adhere to the Standards of Conduct regulations. However, the Standards of Conduct did not apply to natural gas storage providers authorized to charge market-based rates that are not interconnected with the jurisdictional facilities of any affiliated interstate natural gas pipeline, have no exclusive franchise area, no captive ratepayers, and no market power. The FERC has found that PAA/Vulcan’s Pine Prairie Energy Center and its Bluewater facility qualified for this exemption from the Standards of Conduct.


      31

      On November 17, 2006, the D.C. Circuit vacated the Standards of Conduct regulations with respect to natural gas pipelines, and remanded the matter to FERC. On January 9, 2007, FERC issued an interim Standards of Conduct rule that reimposed certain of the Standards of Conduct regulations on interstate natural gas transmission providers while narrowing the regulations in a manner that FERC believes is in compliance with the D.C. Circuit’s remand. The interim rule continues to exempt natural gas storage providers like PAA/Vulcan’s Pine Prairie Energy Center and its Bluewater facility. On January 18, 2007, the FERC issued a Notice of Proposed Rulemaking for new Standards of Conduct regulations. Under the proposed rule, the Standards of Conduct would continue to exempt natural gas storage providers like PAA/Vulcan’s Pine Prairie Energy Center and its Bluewater facility. We are unable to predict what Standards of Conduct regulations FERC will ultimately adopt, or whether those regulations will withstand judicial review.
      On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act to add an antimanipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the antimanipulation provision of EPAct 2005. The rules make it unlawful in connection with the purchase or sale of natural gas or transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new antimanipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also amends the Natural Gas Act and the Natural Gas Policy Act to give FERC authority to impose civil penalties for violations of the Natural Gas Act up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. The antimanipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s Natural Gas Act enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot assure you that the less stringent and pro-competition regulatory approach recently pursued by FERC and Congress will continue.
      State Regulation.  The intrastate storage facilities in which we have an investment are also subject to regulation by the Michigan State Public Service Commission. Specifically, the Michigan State Public Service Commission has authority to regulate our storage facilities in Michigan with respect to safety and environmental matters.
      Environmental, Health and Safety Regulation

      General

              Numerous

      Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons including crude oil are subject to stringent federal, state, provincial and local laws and regulations governing the discharge of materials into the environment or otherwise relating to the protection of the environment, affect our operations and costs. In particular, our activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and wastes are subject to stringent environmental laws and regulations.environment. As with the industry generally, compliance with existing and anticipatedthese laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Although these regulations affect our capital expenditures and earnings, we believe that they do not affect our competitive position because our competitors thatFailure to comply with such laws and regulations are similarly


      affected. Environmental laws and regulations have historically been subject to change, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of such laws and regulations on our operations. Violation of environmental laws and regulations and any associated permits canmay result in the impositionassessment of significant 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 construction bansregulations are subject to change resulting in more stringent requirements, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material effect on our results of operations or delays.earnings. A discharge of petroleum hydrocarbons or hazardous substancesliquids 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 natural resource and property damage.


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      Water

      The U.S. Oil Pollution Act as amended ("OPA"(“OPA”), was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972, as amended ("FWPCA"), and other statutes as they pertain to prevention and response to oil spills. The OPA subjects owners of facilities to strict, joint and potentially unlimited liability for containment and 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$209 million for onshore facilities; however,facilities. However, a party cannot take advantage of this liability limit if the spill is caused by gross negligence or willful misconduct, or resulted from a violation of a federal safety, construction, or operating regulation. Ifregulation, or if there is a party failsfailure to report a spill or cooperate in the cleanup, the liability limits likewise do not apply. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar laws. Regulations have been or are currently being developed under OPA and state laws that may also impose additional regulatory burdens on our operations.cleanup. We believe that we are in substantial compliance with applicable OPA requirements.

      State and Canadian federal and provincial laws also impose requirements relating to the prevention of oil releases and the remediation of areas affected by releases when they occur. We believe that we are in substantial compliance with all such state and Canadian requirements.

      The FWPCA imposesU.S. Clean Water Act and state and Canadian federal and provincial laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States and Canada, as well as state and provincial waters. See Note 11 to our Consolidated Financial Statements. Permits or approvals must be obtained to discharge pollutants into state and federalthese waters. The FWPCAClean Water Act imposes substantial potential liability for the costsremoval and remediation of removal, remediation and damages.pollutants. Although we can give no assurances, we believe that compliance with existing permits and compliance with foreseeable new permit or approval requirements will not have a material adverse effect on our financial condition or results of operations.

      Some states and all provinces 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 theseany such applicable state and provincial 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 releases, 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.
      Air Emissions

      Our operations are subject to the FederalU.S. Clean Air Act as amended, and comparable state local and provincial statutes.laws. Under these laws, permits may be required before construction can commence on a new source of potentially significant air emissions and operating permits may be required for sources already constructed. We may be required to incur certain capital and operating expenditures in the next several years for installing air pollution control equipment and otherwise complying with more stringent state and regional air emissions control plans in connection with obtaining or maintaining permits and approvals for sources of air emissions. Although we believe that our operations are in substantial compliance with these statuteslaws in allthose 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 recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional non-attainment areas require or will 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 will 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. Althoughoperate, we can giveprovide no assurances, we believe on-goingassurance that future compliance with the 1990



      Federal Clean Air Act Amendmentsobligations will not have a material adverse effect on our financial condition or results of operations.

      Further, in response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth’s atmosphere, many foreign nations, including Canada, have agreed to limit emissions of these gases, generally referred to as “greenhouse gases,” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” The Kyoto Protocol requires Canada to reduce its emissions of “greenhouse gases” to 6% below 1990 levels by 2012. As a result, it is possible that already stringent air emissions regulations applicable to our operations in Canada will be replaced with even stricter requirements prior to 2012. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change-related legislation, with multiple bills having already been introduced in the Senate that propose to restrict greenhouse gas emissions. Also, several states have adopted legislation, regulationsand/or regulatory initiatives to reduce emissions of greenhouse gases. For instance, California recently adopted the “California Global Warming Solutions Act of 2006,” which requires the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. Additionally, on November 29, 2006, the U.S. Supreme Court heard arguments on a case appealed from the U.S. Circuit Court of Appeals for the District of Columbia,Massachusetts, et al. v. EPA, in which the appellate court held that the EPA had discretion under the federal Clean Air Act to refuse to regulate carbon dioxide emission from


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      mobile sources. Passage of climate control legislation by Congress or a Supreme Court reversal of the appellate decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases. Any federal, provincial or state restrictions on emissions of greenhouse gases that may be imposed in areas of the United States in which we conduct business or in Canada prior to 2012 could adversely affect our operations and demand for our products.
      Solid Waste

      We generate wastes, including hazardous wastes, that are subject to the requirements of the federal Resource Conservation and Recovery Act ("RCRA"(“RCRA”) and comparable state statutes. The EPA is considering the adoption of stricter disposal standards for non-hazardous wastes, including oil and gas wastes.provincial laws. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities ofprimarily oil and gas wastes, which currently are excluded from consideration as RCRA hazardous wastes. However, it is possible that additional wastes, which could include wastes generated by our operations that are currently classified as non-hazardous wastes, will in the future oil and gas wastes may be designatedincluded as "hazardous wastes." HazardousRCRA hazardous wastes, arein 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 disposal requirements, than are non-hazardous wastes. Such changes in the regulations could resultresulting in additional capital expenditures or operating expenses for us as well asand the industry in general.

      Hazardous Substances

      The federal Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"(“CERCLA”), also known as "Superfund,"“Superfund,” and comparable state 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"“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. Canadian and provincial laws also impose liabilities for releases of certain substances into the environment. 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. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. 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'sCERCLA’s definition of a "hazardous substance." We“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 disposed of or released into the environment.

              We currently own or lease, and have in the past owned or leased, properties where hydrocarbons are being or have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, waste hydrocarbons or other 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 hydrocarbons or other wastes was not under our control. These properties and 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 disposed 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. See "—Environmental Remediation."

      OSHA

      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 keepingrecord-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.

      Similar regulatory requirements exist in Canada under the federal and provincial Occupational Health and Safety Acts and related regulations. The agencies with jurisdiction under these regulations are empowered to enforce them through inspection, audit, incident investigation or public or employee complaint. Additionally, under the Criminal Code of Canada, organizations, corporations and individuals may be prosecuted criminally for violating the duty to protect employee and public safety. We believe that our operations are in substantial compliance with applicable occupational health and safety requirements.
      Endangered Species Act

      The federal Endangered Species Act as amended ("ESA"(“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


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      endangered species could cause us to incur additional costs or operationoperational restrictions or bans in the affected area.

        area, which costs, restrictions, or bans could have a material adverse effect on our financial condition or results of operations. Legislation in Canada for the protection of species at risk and their habitat (the Species at Risk Act) applies to our Canadian operations.

      Hazardous Materials Transportation Requirements

      The federal and analogous state 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—“— Regulation — Pipeline and Storage Regulation."

        ”

      Environmental Remediation

              In connection

      We currently own or lease properties where hazardous liquids, including hydrocarbons, are being or have been handled. These properties and the hazardous liquids or associated generated wastes disposed thereon may be subject to CERCLA, RCRA and state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate 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 operations to prevent future contamination.
      We maintain insurance of various types with varying levels of coverage that we consider adequate under the circumstances to cover our 1999 acquisition of Scurlock Permian LLC from Marathon Ashland Petroleum, or "MAP,"operations and properties. The insurance policies are subject to deductibles and retention levels that we were indemnified by MAP for any environmental liabilities attributable to Scurlock's business or properties which occurred prior to the date of the closing of the acquisition. This indemnity applied to claims associatedconsider reasonable and not excessive. Consistent with sites that were not listedinsurance coverage generally available in the acquisition agreementindustry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and which exceeded $25,000 individually and $1.0 millionaccidental occurrences.
      In addition, we have entered into indemnification agreements with various counterparties in the aggregate. For the indemnity to apply, we were required to assert any claims as to unlisted sites on or before May 15, 2003. In conjunction with the expiration of this indemnity, we reached a settlement agreement with respect to MAP's remaining indemnity obligations. Under the terms of this agreement, MAP will continue to remain obligated for liabilities associated with the sites listed in the acquisition agreement, including two Superfund sites at which it is alleged that Scurlock Permian deposited waste oils. In addition, MAP paid us $4.6 million cash as satisfaction of its obligations with respect to unlisted sites.

              In connection with our acquisition of Murphy Oil Company Ltd.'s midstream operations in Canada, we identified a limited number of environmental deficiencies during due diligence. Under the termsseveral of our acquisition agreement, Murphy, at its sole cost and expense, agreed to remediate (to the minimum standards required by applicable environmental law) the identified environmental deficiencies. For environmental deficiencies that were not identified at the time of acquisition, but which occurred prior to closing, and were identified to Murphy prior to January 31, 2002, we have agreed to be responsible up to an aggregate amount of $300,000. Thereafter, Murphy Oil Company Ltd., agreed to remain solely responsible for the costs to remediate that exceed $20,000 for each environmental deficiency for a total of not more than ten environmental deficiencies as chosen by us. Except for the environmental deficiencies identified at the time of acquisition, Murphy's maximum liability for environmental deficiencies identified post-acquisition cannot exceed $2.25 million. We have identified potential remediation costs for these assets, and have included such costs in the total environmental reserve described below.



              In connection with our acquisition of the West Texas Gathering System, we agreed to be responsible for pre-acquisition environmental liabilities up to an aggregate amount of $1.0 million, while Chevron Pipe Line Company agreed to remain solely responsible for liabilities discovered prior to July 2002 that exceed this $1.0 million threshold. Based on investigations of these assets, we have identified several sites that exceed or will exceed the threshold limitations for the indemnity, and we have notified Chevron of their responsibility to indemnify us for these costs. Our portion of the potential remediation costs have been included in the total environmental reserve described below.

              In connection with the Shell Acquisition 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.

      acquisitions. 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, minimum thresholds or caps on exposure) and whether to obtain insurance, if available. The acquisitionsIn some cases, we completedhave received contractual protections in 2003 includethe form of environmental indemnifications from several predecessor operators for properties acquired by us that are contaminated as a varietyresult of provisions dealinghistorical operations. These contractual indemnifications typically are subject to specific monetary requirements that must be satisfied before indemnification will apply and have term and total dollar limits.

      For instance, in connection with the allocationpurchase of responsibilityassets from Link in 2004, we identified a number of environmental liabilities for which we received a purchase price reduction from Link and recorded a total environmental reserve of $20 million. A substantial portion of these 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 agreed to bear $11 million of the first $20 million of pre-May 1999 environmental issues. We also agreed to bear the first $25,000 per site for new sites which were not identified at the time we entered into the agreement (capped at 100 sites). TNM agreed to pay all costs in excess of $20 million (excluding the deductible for new sites). TNM’s obligations are guaranteed by Shell Oil Products (“SOP”). As of December 31, 2006, we had incurred approximately $7 million of remediation costs associated with these sites; SOP’s share is approximately $1.5 million.
      In connection with the acquisition of certain crude oil transmission and gathering assets from SOP in 2002, SOP 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. SOP made a claim against the policy; however, we do not believe that rangethe claim substantially reduced our coverage under the policy.


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      In connection with our 1999 acquisition of Scurlock Permian LLC from no or limited indemnities from the sellers to indemnification from sellers with defined limitations on their maximum exposure. We have not obtained insuranceMAP, we were indemnified by MAP for any environmental liabilities attributable to Scurlock’s business or properties that occurred prior to the date of the conditions related to our 2003 acquisitions. We believe our exposureclosing of the acquisition. Other than with respect to liabilities associated with two Superfund sites at which it is alleged that Scurlock deposited waste oils, this indemnity has expired or was terminated by agreement.
      As a result of our merger with Pacific, we have assumed liability for a number of ongoing remediation sites, associated with releases from pipeline or storage operations. These sites had been managed by Pacific prior to the acquired propertiesmerger, and in general there is reasonableno insurance or indemnification to cover ongoing costs to address these sites (with the exception of the Pyramid Lake crude oil release, which is discussed in lightItem 3. “Legal Proceedings”). We have evaluated each of all the information available to us, but can give no assurance in that regard. Tosites requiring remediation, through review of technical and regulatory documents, discussions with Pacific, and our experience at investigating and remediating releases from pipeline and storage operations. We have developed reserve estimates for the extent our assessment involves projected costs that are neither indemnified nor insured, we include such costs in our environmental reserve.

      Pacific sites based on this evaluation, including determination of current and long-term reserve amounts, which total approximately $21.8 million.

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

              Our total As we expand our pipeline assets through acquisitions, we typically improve on (decrease) the rate of releases from such assets as we implement our standards and procedures, remove selected assets from service and spend capital to upgrade the assets. In the immediate post-acquisition period, however, the inclusion of additional miles of pipe in our operation may result in an increase in the absolute number of releases company-wide compared to prior periods. We experienced such an increase in connection with the Pacific acquisition, which added approximately 5,000 miles of pipeline to our operations, and in connection with the Link acquisition, which added approximately 7,000 miles of pipeline to our operations. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such releases of crude oil (such as EPA requests under Clean Water Act Section 308), commensurate with the scale and scope of our pipeline operations. See Item 3. “Legal Proceedings.”

      At December 31, 2006, our reserve for environmental liabilities totaled approximately $39.1 million (approximately $21.8 million of this reserve which includes our estimated remediation costs for allis related to liabilities assumed as part of the assets described above, approximated $6.6Pacific merger, and $10.4 million at December 31, 2003. We believe thisis related to liabilities assumed as part of the Link acquisition). Approximately $19.5 million of our environmental reserve is classified as current and $19.6 million is classified as long-term. At December 31, 2006, we have recorded receivables totaling approximately $11.6 million for amounts recoverable under insurance and from third parties under indemnification agreements.
      In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves 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 and the possibility of existing legal claims giving rise to additional claims. Therefore, although we believe that the reserve is adequate, and in conjunction with our indemnification arrangements described above should prevent remediation costs from having a material adverse effect on our financial condition, results of operations or cash flows. However, no assuranceassurances can be givenmade 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.

      Operational Hazards and Insurance

      Pipelines, terminals, trucks or other facilities or equipment 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 the Partnershipwe and itsour 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


      36

      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, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. Over the last several years, our operations have expanded significantly, with total assets increasing approximately 250%over 1,300% 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, theThe overall cost of such insurance as well as the deductibles and overall retention levels that we maintain have increased. Some of this may be attributable to the events of September 11, 2001, which adversely impacted the availability and costs of certain types of coverage. Certain aspects of these conditions were further exacerbated by the hurricanes along the Gulf Coast during 2005, which also had an adverse effect on the availability and cost of coverage. As a result, we have elected to self-insure more activities against certain of these operating hazards and expect this trend will continue in the future. Due to 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 onpolicies. On certain of our key assets, we have elected to purchase a separate insurance policy for acts of terrorism and sabotage.

              This overall trend of contraction in the breadth and depth of available coverage and increases in costs, deductibles and retention levels was reinforced in connection with the renewal of our insurance program in June 2003. Absent a material favorable change in available insurance markets, this trend of rising insurance-related costs is expected to continue as we continue to grow and expand. As a result, it is anticipated that we will elect to self-insure more activities against certain of these operating hazards.

      Since the terrorist attacks, the United States Government has issued numerous warnings that energy assets, (includingincluding our nation'snation’s pipeline infrastructure)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. WeHowever, we cannot assure you that these or any other security measures would protect our facilities from a concentrated attack. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of our competitors, could have a material adverse effect on our business, whether insured or not.

      The occurrence of a significant event not fully insured, indemnified or indemnifiedreserved 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. We believe that our levels of coverage and retention are generally consistent with those of similarly situated companies in our industry. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

      reasonable, or that we have established adequate reserves to the extent that such risks are not insured.

      Title to Properties andRights-of-Way

      We believe that we have satisfactory title to all of our assets. Although title to such properties areis 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 subsequently granted by 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 onrights-of-way granted by the apparent record owners of such property and, in some instances, suchrights-of-way are revocable at the election of the grantor. In many instances, lands over whichrights-of-way have been obtained are subject to prior liens that have not been subordinated to theright-of-way grants. In some cases, not all of the apparent record owners have joined in theright-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 orrights-of-way, many of which are also revocable at the grantor'sgrantor’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 acquirerights-of-way and lands necessary for our common carrier pipelines.


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      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 and Labor Relations

      To carry out our operations, our general partner or its affiliates (including PMC (Nova Scotia) Company) employed approximately 1,3002,900 employees at December 31, 2003.2006. None of the employees of our general partner were represented by labor unions, andsubject to a collective bargaining agreement, except for nine employees at our Paulsboro, New Jersey terminal, who are members of USW District10-286 (Steel Workers), with whom we have a collective bargaining agreement that will end on October 1, 2009. Our general partner considers its employee relations to be good.

      Summary of Tax Considerations

      The tax consequences of ownership of common units depends in part on the owner'sowner’s individual tax circumstances. However, the following is a brief summary of material tax consequencesconsiderations of owning and disposing of common units.

      Partnership Status; Cash Distributions

      We are classifiedtreated for federal income tax purposes as a partnership based upon our meeting certain requirements imposed by the Internal Revenue Code (the "Code"“Code”), which we must meet each year. The owners of common units are considered partners in the Partnership so long as they do not loan their common units to others to cover short sales or otherwise dispose of those units. Accordingly, we pay no U.S. federal income taxes, and a common unitholder is required to report on the unitholder'sunitholder’s federal income tax return the unitholder'sunitholder’s share of our income, gains, losses and deductions. In general, cash distributions to a common unitholder are taxable only if, and to the extent that, they exceed the tax basis in the common units held.

        In certain cases, we are subject to, or have paid Canadian income and withholding taxes. Canadian withholding taxes are due on intercompany interest payments and credits and dividend payments.

      Partnership Allocations

      In general, our income and loss is allocated to the general partner and the unitholders for each taxable year in accordance with their respective percentage interests in the Partnership (including, with respect to the general partner, its incentive distribution right), as determined annually and prorated on a monthly basis and subsequently apportioned among the general partner and the unitholders of record as of the opening of the first business day of the month to which they relate, even though unitholders may dispose of their units during the month in question. AIn determining a unitholder’s federal income tax liability, the unitholder is required to take into account in determining federal income tax liability, the unitholder'sunitholder’s share of income generated by us for each taxable year of the Partnership ending with or within or with the unitholder'sunitholder’s taxable year, even if cash distributions are not made to the unitholder. As a consequence, a unitholder'sunitholder’s share of our taxable income (and possibly the income tax payable by the unitholder with respect to such income) may


      exceed the cash actually distributed to the unitholder by us. At any time incentive distributions are made to the general partner, gross income will be allocated to the recipient to the extent of those distributions.

      Basis of Common Units

      A unitholder'sunitholder’s initial tax basis for a common unit is generally the amount paid for the common unit.unit and the unitholder’s share of our nonrecourse liabilities. A unitholder'sunitholder’s basis is generally increased by the unitholder'sunitholder’s share of our income and by any increases in the unitholder’s share of our nonrecourse liabilities. That basis will be


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      decreased, but not below zero, by the unitholder'sunitholder’s share of our losses and distributions.

        distributions (including deemed distributions due to a decrease in the unitholder’s share of our nonrecourse liabilities).

      Limitations on Deductibility of Partnership Losses

      In the case of taxpayers subject to the passive loss rules (generally, individuals and closely held corporations), any partnership losses are only available to offset future income generated by us and cannot be used to offset income from other activities, including passive activities or investments. Any losses unused by virtue of the passive loss rules may be fully deducted if the unitholder disposes of all of the unitholder'sunitholder’s common units in a taxable transaction with an unrelated party.

      Section 754 Election

      We have made the election provided for by Section 754 of the Code, which will generally result in a unitholder being allocated income and deductions calculated by reference to the portion of the unitholder'sunitholder’s purchase price attributable to each asset of the Partnership.

      Disposition of Common Units

      A unitholder who sells common units will recognize gain or loss equal to the difference between the amount realized and the adjusted tax basis of those common units. A unitholder may not be able to trace basis to particular common units for this purpose. Thus, distributions of cash from us to a unitholder in excess of the income allocated to the unitholder will, in effect, become taxable income if the unitholder sells the common units at a price greater than the unitholder'sunitholder’s adjusted tax basis even if the price is less than the unitholder'sunitholder’s original cost. Moreover, a portion of the amount realized (whether or not representing gain) will be taxed as ordinary income.

        income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.

      Foreign, State, Local and Other Tax Considerations

      In addition to federal income taxes, unitholders will likely be subject to other taxes, such as foreign, state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which a unitholder resides or in which we doconduct business or own property. We own property and conduct business in Canada as well as in most states in the United States. A unitholder maywill therefore be required to file Canadian federal income tax returns and to pay Canadian federal and provincial income taxes as well asin respect of our Canadian source income earned through partnership entities. A unitholder may also be required to file state income tax returns and to pay taxes in various states. A unitholder may be subject to interest and 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 states may require us, or we may elect, 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 more or less than a particular unitholder'sunitholder’s income tax liability owed to thea particular state, may not relieve the nonresident unitholder from the obligation to file an income tax return.return in that state. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.

      It is the responsibility of each prospective unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, including the Canadian provinces and Canada, of the



      unitholder's unitholder’s investment in us. Further, it is the responsibility of each unitholder to file all U.S. federal, Canadian, state, provincial and local tax returns that may be required of the unitholder.

      Ownership of Common Units by Tax-Exempt Organizations and Certain Other Investors

      An investment in common units by tax-exempt organizations (including IRAs and other retirement plans), regulated investment companies (mutual funds) and foreign persons raises issues unique to such persons. Virtually all of our income allocated to a unitholder that is a tax-exempt organization is unrelated business taxable income and, thus, is taxable to such a unitholder. Furthermore, no significant amount of our gross income is qualifying income for purposes of determining whether aA unitholder will qualify as a regulated investment company, and a unitholder


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      who is a nonresident alien, foreign corporation or other foreign person is regarded as being engaged in a trade or business in the United States as a result of ownership of a common unit and, thus, is required to file federal income tax returns and to pay tax on the unitholder'sunitholder’s share of our taxable income. Finally, distributions to foreign unitholders are subject to federal income tax withholding.

      Tax Shelter Registration

              The Code generally requires that "tax shelters" be registered with the Secretary of the Treasury. We are registered as a tax shelter with the Secretary of the Treasury. Our tax shelter registration number is 99061000009. Issuance of the registration number does not indicate that an investment in the Partnership or the claimed tax benefits have been reviewed, examined or approved by the Internal Revenue Service.

      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 the partnership's 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 have been 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.

      Available Information

      We make available, free of charge on our Internet website (www.paalp.com)(http://www.paalp.com), our annual report onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file the material with, or furnish it to, the Securities and Exchange Commission.
      Item 1A.Risk Factors
      Risks Related to 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 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 under futures contracts on the NYMEX, ICE andover-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 physical inventory, futures contracts or derivative products for the purpose of speculating on commodity price changes. These policies and practices cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated physical supply of crude oil could expose us to risk of loss resulting from price changes. We are also exposed to basis risk when crude oil is purchased against one pricing index and sold against a different index. Moreover, we are exposed to some risks that are not hedged, including price risks on certain of our inventory, such as linefill, which must be maintained in order to transport crude oil on our pipelines. In addition, we engage in a controlled trading program for up to an aggregate of 500,000 barrels of crude oil. Although this activity is monitored independently by our risk management function, it exposes us to price risks within predefined limits and authorizations.
      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.
      The nature of our business and assets exposes us to significant compliance costs and liabilities. Our asset base has more than tripled within the last three years. We have experienced a corresponding increase in the relative number of releases of crude oil to the environment. Substantial expenditures may be required to maintain the integrity of aged and aging pipelines and terminals at acceptable levels.
      Our operations involving the storage, treatment, processing, and transportation of liquid hydrocarbons, including crude oil and refined products, as well as our operations involving the storage of natural gas, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment. Our operations are also subject to laws and regulations relating to protection of the environment, operational safety and related matters. Compliance with all of these laws and regulations increases our overall cost of doing 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, the issuance of injunctions that may restrict or prohibit our operations, or claims of damages to property or persons resulting from our operations. The laws and regulations applicable to our operations are subject to change and interpretation by the relevant governmental agency. Any such


      40

      change or interpretation adverse to us could have a material adverse effect on our operations, revenues and profitability.
      Today we own approximately three times the miles of pipeline we owned three years ago. As we have expanded our pipeline assets, we have observed a corresponding increase in the number of releases of crude oil to the environment. These releases expose us to potentially substantial expense, includingclean-up and remediation costs, fines and penalties, and third party claims for personal injury or property damage related to past or future releases. Some of these expenses could increase by amounts disproportionately higher than the relative increase in pipeline mileage and the increase in revenues associated therewith. During 2006, we entered the refined products pipeline and terminalling businesses through the acquisition of three products pipeline systems in West Texas and New Mexico and through the acquisition of Pacific, which had refined product assets in California, the U.S. Rockies and Pennsylvania. These businesses are also subject to significant compliance costs and liabilities. In addition, because of their increased volatility and tendency to migrate farther and faster than crude oil, releases of refined products into the environment can have more significant impact than crude oil and require significantly higher expenditures to respond and remediate. The incurrence of such expenses not covered by insurance, indemnity or reserves could materially adversely affect our results of operations.
      We currently spend substantial amounts to comply with DOT-mandated pipeline integrity rules. The 2006 Pipeline Safety Act, enacted in December 2006, requires the DOT to issue regulations for certain pipelines that were not previously subject to regulation. These regulations could include requirements for the establishment of additional pipeline integrity management programs for these newly regulated pipelines. We do not currently know what, if any, impact this will have on our websiteoperating expenses.
      In addition to performing DOT-mandated pipeline integrity evaluations, during 2006, we expanded an internal review process started in 2005 pursuant to which we review various aspects of our Codepipeline and gathering systems that are not subject to the DOT pipeline integrity management rules. The purpose of Ethicsthis process is to review the surrounding environment, condition and operating history of these pipeline and gathering assets to determine if such assets warrant additional investment or replacement. Accordingly, we could be required (as a result of additional DOT regulation) or we may elect (as a result of our own internal initiatives) 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 Senior Financial Officers. Any waiverenvironmental compliance.
      Loss of such Codecredit rating or the ability to receive open credit could negatively affect our ability to use the counter-cyclical aspects of our asset base or to capitalize on a volatile market.
      We believe that, because of our strategic asset base and complementary business model, we will alsocontinue to benefit from swings in market prices and shifts in market structure during periods of volatility in the crude oil market. Our ability to capture that benefit, however, is subject to numerous risks and uncertainties, including our maintaining an attractive credit rating and continuing to receive open credit from our suppliers and trade counter-parties.
      We may not be postedable to fully implement or capitalize upon planned growth projects.
      We have a number of organic growth projects that require the expenditure of significant amounts of capital, including the Pier 400 project, the Salt Lake City expansion, the Cheyenne pipeline project, the Pine Prairie joint venture and the St. James, Cushing and Patoka terminal projects. Many of these projects involve numerous regulatory, environmental, weather-related, political and legal uncertainties that will be beyond our control. As these projects are undertaken, required approvals may not be obtained, may be delayed or may be obtained with conditions that materially alter the expected return associated with the underlying projects. Moreover, revenues associated with these organic growth projects will not increase immediately upon the expenditures of funds with respect to a particular project and these projects may be completed behind schedule or in excess of budgeted cost. Because of continuing increased demand for materials, equipment and services, there could be shortages and cost increases associated with construction projects. We may construct pipelines, facilities or other assets in anticipation


      41

      of market demand that dissipates or market growth that never materializes. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved.
      The level of our profitability is dependent upon an adequate supply of crude oil from fields located offshore and onshore California. A shut-in of this production due to economic limitations or a significant event could adversely affect our profitability. In addition, these offshore fields have 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 and the onshore fields in the San Joaquin Valley. 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 transportation segment profit of approximately $6.1 million. A similar decline in volumes shipped from the San Joaquin Valley would result in an estimated $3.2 million decrease in annual transportation segment profit. In addition, any significant production disruption from the outer continental shelf fields and the San Joaquin Valley due to production problems, transportation problems or other reasons could have a material adverse effect on our website. Youbusiness.
      Our profitability depends on the volume of crude oil, refined product and LPG shipped, purchased and gathered.
      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 average 20,000 barrel per day variance in the Basin Pipeline System within the current operating window, equivalent to an approximate 7% volume variance on that system, would change annualized segment profit by approximately $1.8 million. In addition, we estimate that an average 10,000 barrel per day variance on the Capline Pipeline System, equivalent to an approximate 8% volume variance on that system, would change annualized segment profit by approximately $1.3 million.
      To maintain the volumes of crude oil we purchase in connection with our operations, 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 relationships already exist between producers and other gatherers and purchasers of crude oil. We estimate that a 15,000 barrel per day decrease in barrels gathered by us would have an approximate $2.7 million per year negative impact on segment profit. This impact assumes 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. We estimate that a $0.01 variance in the average segment profit per barrel would have an approximate $4.2 million annual effect on segment profit.
      Fluctuations in demand can negatively affect our operating results.
      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 Section 16 reportsto our transportation assets to satisfy their demand by deliveries through those assets.
      Fluctuations in demand for crude oil, such as caused by refinery downtime or shutdown, can have a negative effect on our website.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


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      our ability to capture differentials created by demand fluctuations, this ability is dependent on location and grade of crude oil, and thus is unpredictable.

      Item 3.    

      Legal ProceedingsIf we do not make acquisitions on economically acceptable terms our future growth may be limited.
      Our ability to grow depends in part 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 we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with the sellers, (ii) unable to raise financing for such acquisitions on economically acceptable terms or (iii) outbid by competitors, our future growth will be limited. In particular, competition for midstream assets and businesses has intensified substantially and as a consequence such assets and businesses 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 capital markets or other factors that increase our cost of capital could impair our ability to grow through acquisitions.
      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 affect 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:
      • performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;
      • a significant increase in our indebtedness and working capital requirements;
      • the inability to timely and effectively integrate the operations of recently acquired businesses or assets;
      • the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets prior to our acquisition;
      • risks associated with operating in lines of business that are distinct and separate from our historical operations;
      • customer or key employee loss from the acquired businesses; and
      • the diversion of management’s attention from other business concerns.
      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 pay distributions or meet our debt service requirements.
      Our pipeline assets are subject to federal, state and provincial regulation. Rate regulation or a successful challenge to the rates we charge on our domestic interstate pipeline system may reduce the amount of cash we generate.
      Our domestic interstate common carrier pipelines are subject to regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines be just and reasonable and non-discriminatory. We are also subject to the Pipeline Safety Regulations of the DOT. Our intrastate pipeline transportation activities are subject to various state laws and regulations as well as orders of regulatory bodies.


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      The EPAct, among other things, deems “just and reasonable” within the meaning of the Interstate Commerce Act any oil pipeline rate in effect for the365-day period ending on the date of the enactment of EPAct if the rate in effect was not subject to protest, investigation, or complaint during such365-day period. (That is, the EPAct “grandfathers” any such rates.) The EPAct further protects any rate meeting this requirement from complaint unless the complainant can show that a substantial change occurred after the enactment of EPAct in the economic circumstances of the oil pipeline which were the basis for the rate or in the nature of the services provided which were a basis for the rate. This grandfathering protection does not apply, under certain specified circumstances, when the person filing the complaint was under a contractual prohibition against the filing of a complaint.
      For our domestic interstate common carrier pipelines subject to FERC regulation under the Interstate Commerce Act, shippers may protest our pipeline tariff filings, and the FERC may investigate new or changed tariff rates. Further, other than for rates set under market-based rate authority and for rates that remain grandfathered under EPAct, the FERC may order refunds of amounts collected under rates that were in excess of a just and reasonable level when taking into consideration the pipeline system’s cost of service. In addition, shippers may challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint. The FERC’s ratemaking methodologies may limit our ability to set rates based on our true costs or may delay the use of rates that reflect increased costs.
      The potential for a challenge to the status of our grandfathered rates under EPAct (by showing a substantial change in circumstances) or a challenge to our indexed rates creates the risk that the FERC might find some of our rates to be in excess of a just and reasonable level — that is, a level justified by our cost of service. In such an event, the FERC could order us to reduce any such rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint.
      Our Canadian pipelines are subject to regulation by the NEB or by provincial authorities. Under the National Energy Board Act, the NEB could investigate the tariff rates or the terms and conditions of service relating to a jurisdictional pipeline on its own initiative upon the filing of a toll or tariff application, or upon the filing of a written complaint. If it found the rates or terms of service relating to such pipeline to be unjust or unreasonable or unjustly discriminatory, the NEB could require us to change our rates, provide access to other shippers, or change our terms of service. A provincial authority could, on the application of a shipper or other interested party, investigate the tariff rates or our terms and conditions of service relating to our provincially regulated proprietary pipelines. If it found our rates or terms of service to be contrary to statutory requirements, it could impose conditions it considers appropriate. A provincial authority could declare a pipeline to be a common carrier pipeline, and require us to change our rates, provide access to other shippers, or otherwise alter our terms of service. Any reduction in our tariff rates would result in lower revenue and cash flows.
      Some of our operations cross the U.S./Canada border and are subject to cross border regulation.
      Our cross border activities with our Canadian subsidiaries subject us to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Regulations include the Short Supply Controls of the Export License Matter.Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.
      We face competition in our transportation, facilities 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.
      With respect to our natural gas storage operations, we compete with other storage providers, including local distribution companies (“LDCs”), utilities and affiliates of LDCs and utilities. Certain major pipeline companies have existing storage facilities connected to their systems that compete with certain of our facilities. Third-party construction of new capacity could have an adverse impact on our competitive position.


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      We are exposed to the credit risk of our customers in the ordinary course of our marketing activities.
      There can be no assurance that we have adequately assessed the creditworthiness of our existing or future counterparties or that there will not be an unanticipated deterioration in their creditworthiness, which could have an adverse impact on us.
      In those cases in which 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.
      We may in the future encounter increased costs related to, and lack of availability of, insurance.
      Over the last several years, as the scale and scope of our business activities has expanded, the breadth and depth of available insurance markets has contracted. Some of this may be attributable to the events of September 11, 2001 and the effects of hurricanes along the Gulf Coast during 2005, which adversely impacted the availability and costs of certain types of coverage. We can give no assurance that we will be able to maintain adequate insurance in the future at rates we consider reasonable. The occurrence of a significant event not fully insured could materially and adversely affect our operations and financial condition.
      Marine transportation of crude oil and refined product has inherent operating risks.
      Our gathering and marketing activities, we import and exportoperations include purchasing crude oil from and to Canada. Exportsthat is carried on third-party tankers. Our waterborne cargoes of crude oil are at risk of being damaged or lost because of events such as marine disaster, bad weather, mechanical failures, grounding or collision, fire, explosion, environmental accidents, piracy, terrorism and political instability. Such occurrences could result in death or injury to persons, loss of property or environmental damage, delays in the delivery of cargo, loss of revenues from or termination of charter contracts, governmental fines, penalties or restrictions on conducting business, higher insurance rates and damage to our reputation and customer relationships generally. Although certain of these risks may be covered under our insurance program, any of these circumstances or events could increase our costs or lower our revenues.
      In instances in which cargoes are purchased FOB (title transfers when the oil is loaded onto a vessel chartered by the purchaser) the contract to purchase is typically made prior to the vessel being chartered. In such circumstances we take the risk of higher than anticipated charter costs. We are also exposed to increased transit time and unanticipated demurrage charges, which involve extra payment to the owner of a vessel for delays in offloading, circumstances that we may not control.
      Maritime claimants could arrest the vessels carrying our cargoes.
      Crew members, suppliers of goods and services to a vessel, other shippers of cargo and other parties may be entitled to a maritime lien against that vessel for unsatisfied debts, claims or damages. In many jurisdictions, a maritime lienholder may enforce its lien by arresting a vessel through foreclosure proceedings. The arrest or attachment of a vessel carrying a cargo of our oil could substantially delay our shipment.
      In addition, in some jurisdictions, under the “sister ship” theory of liability, a claimant may arrest both the vessel that is subject to the short supply controlsclaimant’s maritime lien and any “associated” vessel, which is any vessel owned or controlled by the same owner. Claimants could try to assert “sister ship” liability against one vessel carrying our cargo for claims relating to a vessel with which we have no relation.
      We are dependent on use of a third-party marine dock for delivery of waterborne crude oil into our storage and distribution facilities in the Los Angeles basin.
      A portion of our storage and distribution business conducted in the Los Angeles basin (acquired in connection with the Pacific acquisition) is dependent on our ability to receive waterborne crude oil, a major portion of which is presently being received through dock facilities operated by Shell Oil Products in the Port of Long Beach. We are currently a hold-over tenant with respect to such facilities. If we are unable to renew the agreement that allows us to utilize these dock facilities, and if other alternative dock access cannot be arranged, the volumes of crude oil that we


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      presently receive from our customers in the Los Angeles basin may be reduced, which could result in a reduction of facilities segment revenue and cash flow.
      The terms of our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.
      As of December 31, 2006, our total outstanding long-term debt was approximately $2.6 billion. Various limitations in certain of our debt instruments 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 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.
      Terrorist attacks aimed at our facilities could adversely affect our business.
      Since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. These developments will subject our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.
      An impairment of goodwill could reduce our earnings.
      We recorded a significant amount of goodwill upon completion of our merger with Pacific, but our preliminary estimate is subject to change pending the completion of an independent appraisal. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the Export Administration Regulations ("EAR")acquired tangible and mustseparately measurable intangible net assets. U.S. generally accepted accounting principles, or GAAP, requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be licensedimpaired. If we were to determine that any of our remaining balance of goodwill was impaired, we would be required to take an immediate charge to earnings with a corresponding reduction of partners’ equity and increase in balance sheet leverage as measured by debt to total capitalization.
      Our natural gas storage facilities are new and have limited operating history.
      Although we believe that our operating natural gas storage facilities are designed substantially to meet our contractual obligations with respect to injection and withdrawal volumes and specifications, the facilities are new and have a limited operating history. If we fail to receive or deliver natural gas at contracted rates, or cannot deliver natural gas consistent with contractual quality specifications, we could incur significant costs to maintain compliance with our contracts.
      We have a limited history of operating natural gas storage facilities and transporting, storing and marketing refined products.
      Although many aspects of the natural gas storage and refined products industries are similar to our crude oil operations, our current management has little experience in operating natural gas storage facilities or in the refined products business. There are significant risks and costs inherent in our efforts to engage in these operations, including the risk that our new lines of business may not be profitable and that we might not be able to operate them or implement our operating policies and strategies successfully.
      The devotion of capital, management time and other resources to natural gas storage and refined products operations could adversely affect our existing business. Entering into the natural gas storage and refined products industries may require substantial changes, including acquisition costs, capital development expenditures, adding skilled management and employees and realigning our current organization to reflect these new lines of business.


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      Entering into the natural gas storage industry will require an investment in personnel and assets and the assumption of risks that may be greater than we have previously assumed.
      Federal, state or local regulatory measures could adversely affect our natural gas storage business.
      Our natural gas storage operations are subject to federal, state and local regulation. Specifically, our natural gas storage facilities and related assets are subject to regulation by the BureauFERC, the Michigan Public Service Commission and various Louisiana state agencies. Our facilities essentially have market-based rate authority from such agencies. Any loss of Industrymarket-based rate authority could have an adverse impact on our revenues associated with providing storage services. In addition, failure to comply with applicable regulations under the Natural Gas Act, and Securitycertain other state laws could result in the imposition of administrative, civil and criminal remedies.
      Our gas storage business depends on third party pipelines to transport natural gas.
      We depend on third party pipelines to move natural gas for our customers to and from our facilities. Any interruption of service on the pipelines or lateral connections or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our facilities, and could have a corresponding material adverse effect on our storage revenues. In addition, the rates charged by the interconnected pipeline for transportation to and from our facilities could affect the utilization and value of our storage services. Significant changes in the rates charged by the pipeline or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.
      We may not be able to retain existing natural gas storage customers or acquire new customers, which would reduce our revenues and limit our future profitability.
      The renewal or replacement of existing contracts with our customers at rates sufficient to maintain or exceed current or anticipated revenues and cash flows depends on a number of factors beyond our control, including competition from other storage providers and the supply of and demand for natural gas in the markets we serve. The inability to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.
      Joint venture structures can create operational difficulties.
      Our natural gas storage operations are conducted through PAA/Vulcan, a joint venture between us and a subsidiary of Vulcan Capital. We are also engaged in a joint venture arrangement with Settoon Towing.
      As with any joint venture arrangement, differences in views among the joint venture participants may result in delayed decisions or in failures to agree on major matters, potentially adversely affecting the business and operations of the joint ventures and in turn our business and operations.
      Risks Inherent in an Investment in Plains All American Pipeline, L.P.
      Cost reimbursements due to our general partner may be substantial and will reduce our cash available for distribution to unitholders.
      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.
      Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.
      Because distributions on the common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter


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      will depend on numerous factors, some of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits.
      Unitholders may not be able to remove our general partner even if they wish to do so.
      Our general partner manages and operates the Partnership. Unlike the holders of common stock in a corporation, unitholders will have only limited voting rights on matters affecting our business. Unitholders have no right to elect the general partner or the directors of the general partner on an annual or any other basis.
      Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have little practical ability to remove our general partner or otherwise change its management. Our general partner may not be removed except upon the vote of the holders of at least 662/3% of our outstanding units (including units held by our general partner or its affiliates). Because the owners of our general partner, along with directors and executive officers and their affiliates, own a significant percentage of our outstanding common units, the removal of our general partner would be difficult without the consent of both our general partner and its affiliates.
      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:
      • generally, if a person acquires 20% or more of any class of units then outstanding other than from our general partner or its affiliates, the units owned by such person cannot be voted on any matter; and
      • limitations upon the ability of unitholders to call meetings or to acquire information about our operations, as well as other limitations upon the unitholders’ ability to influence the manner or direction of 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 unitholder approval, which would dilute a unitholder’s existing ownership interests.
      Our general partner may cause us to issue an unlimited number of common units, without unitholder approval (subject to applicable NYSE rules). We may also issue at any time an unlimited number of equity securities ranking junior or senior to the common units without unitholder approval (subject to applicable NYSE rules). The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:
      • an existing unitholder’s proportionate ownership interest in the Partnership will decrease;
      • the amount of cash available for distribution on each unit may decrease;
      • the relative voting strength of each previously outstanding unit may be diminished; and
      • the market price of the common units may decline.
      Our general partner has a limited call right that may require unitholders to sell their 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, unitholders may be required to sell their common units at a time when they may not desire to sell them or at a price that is less than the price they would like to receive. They may also incur a tax liability upon a sale of their common units.


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      Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.
      Under Delaware law, a unitholder 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:
      • we do not have any employees and we rely solely on employees of the general partner or, in the case of Plains Marketing Canada, employees of PMC (Nova Scotia) Company;
      • under our partnership agreement, we reimburse the general partner for the costs of managing and for operating the partnership;
      • the amount of cash expenditures, borrowings and reserves in any quarter may affect available cash to pay quarterly distributions to unitholders;
      • the general partner tries to avoid being liable for partnership obligations. The general partner is permitted to protect its assets in this manner by our partnership agreement. Under our partnership agreement the general partner would not breach its fiduciary duty by avoiding liability for partnership obligations even if we can obtain more favorable terms without limiting the general partner’s liability; under our partnership agreement, the general partner may pay its affiliates for any services rendered on terms fair and reasonable to us. The general partner may also enter into additional contracts with any of its affiliates on behalf of us. Agreements or contracts between us and our general partner (and its affiliates) are not necessarily the result of arms length negotiations; and
      • the general partner would not breach our partnership agreement by exercising its call rights to purchase limited partnership interests or by assigning its call rights to one of its affiliates or to us.
      The control of our general partner may be transferred to a third party without unitholder consent. A change of control may result in defaults under certain of our debt instruments and the triggering of payment obligations under compensation arrangements.
      Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the general partner of our general partner from transferring its general partnership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers with its own choices and to control their decisions and actions.
      In addition, a change of control would constitute an event of default under the indentures governing certain issues of our senior notes and under our revolving credit agreement. An event of default under certain of our indentures could require us to make an offer to purchase the senior notes issued thereunder at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest, if any, to the date of purchase. During the continuance of an event of default under our revolving credit agreement, the administrative agent may terminate any outstanding commitments of the lenders to extend credit to us under our revolving credit facilityand/or declare all amounts payable by us under our revolving credit facility immediately due and payable. A change of control also may trigger payment obligations under various compensation arrangements with our officers.


      49

      Risks Related to an Investment in Our Debt Securities
      The right to receive payments on our outstanding debt securities and subsidiary guarantees is unsecured and will be effectively subordinated to our existing and future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the notes.
      Our debt securities are effectively subordinated to claims of our secured creditors and the guarantees are effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Although substantially all of our operating subsidiaries, other than minor subsidiaries and those regulated by the CPUC, have guaranteed such debt securities, the guarantees are subject to release under certain circumstances, and we may have subsidiaries that are not guarantors. In that case, the debt securities would be effectively subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the debt securities.
      Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.
      Our leverage is significant in relation to our partners’ capital. At December 31, 2006, our total outstanding long-term debt and short-term debt under our revolving credit facility was approximately $3.6 billion. We will be prohibited from making cash distributions during an event of default under any of our indebtedness. Various limitations in our credit facilities 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.
      Our leverage could have important consequences to investors in our debt securities. We will require substantial cash flow to meet our principal and interest obligations with respect to the notes and our other consolidated indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our bank credit facility to service our indebtedness, although the principal amount of the notes will likely need to be refinanced at maturity in whole or in part. However, a significant downturn in the hydrocarbon industry or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or portion of our debt or sell assets. We can give no assurance that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable. In addition, if one or more rating agencies were to lower our debt ratings, we could be required by some of our counterparties to post additional collateral, which would reduce our available liquidity and cash flow.
      Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisition, construction or development activities, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.
      A court may use fraudulent conveyance considerations to avoid or subordinate the subsidiary guarantees.
      Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. A court may use fraudulent conveyance laws to subordinate or avoid the subsidiary guarantees of our debt securities issued by any of our subsidiary guarantors. It is also possible that under certain circumstances a court could hold that the direct


      50

      obligations of a subsidiary guaranteeing our debt securities could be superior to the obligations under that guarantee.
      A court could avoid or subordinate the guarantee of our debt securities by any of our subsidiaries in favor of that subsidiary’s other debts or liabilities to the extent that the court determined either of the following were true at the time the subsidiary issued the guarantee:
      • that subsidiary incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or that subsidiary contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or
      • that subsidiary did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, that subsidiary:
      — was insolvent or rendered insolvent by reason of the issuance of the guarantee;
      — was engaged or about to engage in a business or transaction for which the remaining assets of that subsidiary constituted unreasonably small capital; or
      — intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.
      The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation, or if the present fair saleable value of its assets were less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and matured.
      Among other things, a legal challenge of a subsidiary’s guarantee of our debt securities on fraudulent conveyance grounds may focus on the benefits, if any, realized by that subsidiary as a result of our issuance of our debt securities. To the extent a subsidiary’s guarantee of our debt securities is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of our debt securities would cease to have any claim in respect of that guarantee.
      The ability to transfer our debt securities may be limited by the absence of a trading market.
      We do not currently intend to apply for listing of our debt securities on any securities exchange or stock market. The liquidity of any market for our debt securities will depend on the number of holders of those debt securities, the interest of securities dealers in making a market in those debt securities and other factors. Accordingly, we can give no assurance as to the development or liquidity of any market for the debt securities.
      We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
      We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make required payments on our debt securities depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. Pursuant to the credit facilities, we may be required to establish cash reserves for the future payment of principal and interest on the amounts outstanding under our credit facilities. If we are unable to obtain the funds necessary to pay the principal amount at maturity of the debt securities, or to repurchase the debt securities upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of the debt securities. We cannot assure you that we would be able to refinance the debt securities.


      51

      We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt securities or to repay them at maturity.
      Unlike a corporation, our partnership agreement requires us to distribute, on a quarterly basis, 100% of our available cash to our unitholders of record and our general partner. Available cash is generally all of our cash receipts adjusted for cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to establish and make additions to our reserves or the reserves of our operating partnerships in amounts the general partner determines in its reasonable discretion to be necessary or appropriate:
      • to provide for the proper conduct of our business and the businesses of our operating partnerships (including reserves for future capital expenditures and for our anticipated future credit needs);
      • to provide funds for distributions to our unitholders and the general partner for any one or more of the next four calendar quarters; or
      • to comply with applicable law or any of our loan or other agreements.
      Although our payment obligations to our unitholders are subordinate to our payment obligations to debtholders, the value of our units will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue equity to recapitalize.
      Tax Risks to Common Unitholders
      Our tax treatment depends on our status as a partnership for U.S. and Canadian federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available to pay distributions and our debt obligations.
      If we were treated as a corporation for U.S. 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%, and would likely pay state income tax at varying rates. Because a tax would be imposed upon us as a corporation, the cash available for distributions or to pay our debt obligations would be substantially reduced.
      Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we will be subject to a new entity level tax on the portion of our income that is generated in Texas beginning in our tax year ending in 2007. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. Imposition of such a tax upon us as an entity by Texas or any other state will reduce the cash available for distributions or to pay our debt obligations.
      Proposed changes in Canadian tax law could subject our Canadian subsidiaries to entity-level tax, which would reduce the amount of cash available to pay distributions and our debt obligations.
      In response to the perceived proliferation of “income trusts” in Canada, the Canadian government has issued proposed regulations that impose entity-level taxes on certain types of flow-through entities. At this point, final regulations have not been issued and it is not clear what impact the final regulations will have on our Canadian subsidiaries. Any entity-level taxation of our Canadian subsidiaries would reduce the cash available for distributions or to pay our debt obligations.


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      The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in our termination as a partnership for federal income tax purposes.
      We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all of our unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.
      If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution or debt service.
      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 or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of 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 because the costs will reduce our cash available for distribution or debt service.
      Our unitholders may be required to pay taxes even if they do not receive any cash distributions from us.
      Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
      Tax gain or loss on disposition of common units could be different than expected.
      If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income allocated to a unitholder for a common unit, which decreased the unitholder’s tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price the unitholder receives is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder. Should the IRS successfully contest some positions we take, the unitholder 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 a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.
      Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
      Investment in common units by tax-exempt entities, such as individual retirement accounts (IRAs), andnon-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are 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. Distributions tonon-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, andnon-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income.


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      We treat each purchaser of common units as having the same tax benefits without regard to the actual 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 and because of other reasons, 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 our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to a unitholder’s tax return.
      Our unitholders will likely be subject to foreign, state and local taxes and tax return filing requirements in jurisdictions where they do not live as a result of an investment in our units.
      In addition to federal income taxes, our unitholders 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 conduct business or own property and in which they do not reside. We own property and conduct business in Canada and in most states in the United States. Unitholders will be required to file Canadian federal income tax returns and to pay Canadian federal and provincial income taxes in respect of our Canadian source income earned through partnership entities. A unitholder may also be required 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 conduct business or own property. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders’ responsibility to file all United States federal, state, local and foreign tax returns.
      Item 1B.Unresolved Staff Comments
      None.
      Item 3.Legal Proceedings
      Pipeline Releases.  In January 2005 and December 2004, we experienced two unrelated releases of crude oil that reached rivers located near the sites where the releases originated. In early January 2005, an overflow from a temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains, the U.S. Environmental Protection Agency (the "BIS"“EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conductedclean-up operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $3.0 million to $3.5 million. In cooperation with the appropriate state and federal environmental authorities, we have substantially completed our work with respect to site restoration, subject to some ongoing remediation at the Pecos River site. EPA has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Commerce.Justice (the “DOJ”) for further investigation in connection with a possible civil penalty enforcement action under the Federal Clean Water Act. We are cooperating in the investigation. Our assessment is that it is probable we will pay penalties related to the two releases. We have determinedaccrued the estimated loss contingency, which is included in the estimated aggregate costs set forth above. It is reasonably possible that wethe loss contingency may have exceededexceed our estimate with respect to penalties assessed by the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. On October 2, 2003, we submitted additional information to the BIS. At this time,DOJ; however, we have received no indication whetherfrom EPA or the BIS intends to charge us with a violationDOJ of the EAR or, if so, what penalties wouldmight be assessed.sought. As a result, we cannotare unable to estimate the ultimate impactrange of a reasonably possible loss contingency in excess of our accrual.
      On November 15, 2006, we completed the Pacific acquisition. The following is a summary of the more significant matters that relate to Pacific, its assets or operations.
      The People of the State of California v. Pacific Pipeline System, LLC (“PPS”).  In March 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63, subsequently acquired by us in the Pacific merger.


      54

      The release occurred when Line 63 was severed as a result of a landslide caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. As of December 31, 2006, $26 million of remediation costs had been incurred. We estimate additional remediation costs of approximately $1 to $2 million, substantially all of which we expect to incur before June 2007. We anticipate that the majority of costs associated with this release will be covered under a pre-existing PPS pollution liability insurance policy.
      In March 2006, PPS, a subsidiary acquired in the Pacific merger, was served with a four count misdemeanor criminal action in the Los Angeles Superior Court Case No. 6NW01020, which alleges the violation by PPS of two strict liability statutes under the California Fish and Game Code for the unlawful deposit of oil or substances harmful to wildlife into the environment, and violations of two sections of the California Water Code for the willful and intentional discharge of pollution into state waters. The fines that can be assessed against PPS for the violations of the strict liability statutes are based, in large measure, on the volume of unrecovered crude oil that was released into the environment, and, therefore, the maximum state fine that can be assessed is estimated to be approximately $1,100,000, in the aggregate. This amount is subject to a downward adjustment with respect to actual volumes of recovered crude oil, and the State of California has the discretion to further reduce the fine after considering other mitigating factors. Because of the uncertainty associated with these factors, the final amount of the fine that will be assessed for the strict liability offenses cannot be ascertained. We will defend against these charges. In addition to these fines, the State of California has indicated that it may seek to recover approximately $150,000 in natural resource damages against PPS in connection with this matter.

      The mitigating factors may also serve as a basis for a downward adjustment of the natural resource damages amount. We believe that certain of the alleged violations are without merit and intend to defend against them, and that mitigating factors should apply.

      In December 2006 we were informed that the EPA may be intending to refer this matter to the DOJ for the initiation of proceedings to assess civil penalties against PPS. The DOJ has accepted the referral. We understand that the maximum permissible penalty that the EPA could assess under relevant statutes would be approximately $3.7 million. We believe that several mitigating circumstances and factors exist that could substantially reduce the penalty, and intend to pursue discussions with the EPA regarding such mitigating circumstances and factors. Because of the uncertainty associated with these factors, the final amount of the penalty that will be assessed by the EPA cannot be ascertained. Discussions with the DOJ to resolve this matter have commenced.
              Alfons SperberKosseff v. Plains Resources Inc.Pacific Energy, et al, et. al.case no. BC 3544016. On December 18, 2003,June 15, 2006, a putative class action lawsuit was filed in the Delaware Chancery Court, New CastleSuperior court of California, County entitledAlfons Sperber v. Plains Resources Inc., et al. This suit,of Los Angeles, in which the plaintiff alleged that he was a unitholder of Pacific and he sought to represent a class comprising all of Pacific’s unitholders. The complaint named as defendants Pacific and certain of the officers and directors of Pacific’s general partner, and asserted claims of self-dealing and breach of fiduciary duty in connection with the pending merger with us and related transactions. The plaintiff sought injunctive relief against completing the merger or, if the merger was completed, rescission of the merger, other equitable relief, and recovery of the plaintiff’s costs and attorneys’ fees. On September 14, 2006, Pacific and the other defendants entered into a memorandum of settlement with the plaintiff to settle the lawsuit. As part of the settlement, Pacific and the other defendants deny all allegations of wrongdoing and express willingness to settle the lawsuit solely because the settlement would eliminate the burden and expense of further litigation. The settlement is subject to customary conditions, including court approval. As part of the settlement, we (as successor to Pacific) will pay $0.5 million to the plaintiff’s counsel for their fees and expenses, and incur the cost of mailing materials to former Pacific unitholders. If finally approved by the court, the settlement will resolve all claims that were or could have been brought on behalf of a putativethe proposed settlement class of Plains All American Pipeline, L.P. common unit holders, asserts breach of fiduciary dutyin the actions being settled, including all claims relating to the merger, the merger agreement and breach of contract claims againstany disclosure made by Pacific in connection with the Partnership, 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.merger. The complaint seeks to enjoin or rescind a proposed acquisition of allsettlement did not change any of the outstanding stockterms or conditions of Plains Resources Inc.the merger.
      Air Quality Permits.  In connection with the Pacific merger, we acquired Pacific Atlantic Terminals LLC (“PAT”), as well as declaratory relief, an accounting, disgorgementwhich is now one of our subsidiaries. PAT owns crude oil and refined products terminals in northern California. In the impositionprocess of integrating PAT’s assets into our operations, we identified certain aspects of the operations at the terminals that appeared to be out of compliance with specifications under the relevant air quality permit. We conducted a constructive trust,prompt review of the circumstances and an awardself-reported the apparent historical occurrences of damages, fees, expenses and costs, among other things. The Partnership intendsnon-compliance to vigorously defend this lawsuit.the Bay Area Air Quality Management District. We are cooperating with the District’s review of these matters.


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              Other.General.  We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. 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.

      Item 4.    

      Item 4.Submission of Matters to a Vote of Security Holders
      On November 9, 2006, the Partnership held a special meeting of Matters to a Vote of Security Holders

              No matters were submitted to aits unitholders for the following purposes:

      1. To consider and vote upon the approval and adoption of the security holders, through solicitationAgreement and Plan of proxies or otherwise, duringMerger dated as of June 11, 2006 by and among the fiscal year covered by this report.

      Partnership, Plains AAP, L.P., Plains All American GP LLC, Pacific, Pacific Energy Management LLC and Pacific Energy GP, LP, as it may be amended from time to time (the “Merger Agreement”); and


      PART II

      Item 5.    Market For

      2. To consider and vote upon the Registrant's Common Units and Related Unitholder Matters

              Theapproval of the issuance of our common units excludingto the Class Bcommon unitholders of Pacific (other than LB Pacific, LP), as provided in the Merger Agreement.

      Holders of over 65% of our outstanding common units voted in favor of both proposals. The voting results were as follows:
                       
        Votes Cast  Broker
      		 
      Matter
      		 For  Against  Abstain  Non-Votes 
       
      Approve Merger Agreement  52,832,920   297,858   261,365   n/a 
      Approve Issuance of Units Pursuant to Merger Agreement  52,733,280   373,438   285,425   n/a 
      PART II
      Item 5.Market For Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities
      Our common units are listed and traded on the New York Stock Exchange (“NYSE”) under the symbol "PAA".“PAA.” On February 17, 2004,20, 2007, the closing market price for theour common units was $32.12$54.67 per unit and there were approximately 30,00070,000 record holders and beneficial owners (held in street name). As of February 17, 2004,20, 2007, there were 57,162,638109,405,178 common units outstanding and 1,307,190 Class B common units outstanding. The number of common units outstanding on this date includes the 10,029,619 common units that converted from Subordinated Units in November 2003 and February 2004.

      The following table sets forth high and low sales prices for theour common units and the cash distributions paiddeclared per common unit for the periods indicated:
                   
        Common
      		    
        Unit Price Range  Cash
      		 
        High  Low  Distributions(1) 
       
      2006
      		            
      1st Quarter $47.00  $39.81  $0.7075 
      2nd Quarter  48.92   42.81   0.7250 
      3rd Quarter  47.35   43.21   0.7500 
      4th Quarter  53.23   45.20   0.8000 
      2005
      		            
      1st Quarter $40.98  $36.50  $0.6375 
      2nd Quarter  45.08   38.00   0.6500 
      3rd Quarter  48.20   42.01   0.6750 
      4th Quarter  42.82   38.51   0.6875 


      56

       
      		 Common Unit Price Range
      		  
       
      		 Cash
      Distributions(1)
       
      		 High
      		 Low
      2002         
       1st Quarter $26.79 $23.60 $0.5250
       2nd Quarter  27.30  24.60  0.5375
       3rd Quarter  26.38  19.54  0.5375
       4th Quarter  24.44  22.04  0.5375

      2003
       
       
       
       
       
       
       
       
       
       1st Quarter $26.90 $24.20 $0.5500
       2nd Quarter  31.48  24.65  0.5500
       3rd Quarter  32.49  29.10  0.5500
       4th Quarter  32.82  29.76  0.5625
      (1)
      Cash distributions are paid in the following calendar quarter.

              The Class B

      (1)Cash distributions for a quarter are declared and paid in the following calendar quarter.
      Our common units are pari passu with common units with respectused as a form of compensation to quarterly distributions,our employees. Additional information regarding our equity compensation plans is included in Part III of this report under Item 13. “Certain Relationships and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, the Class B units have the same voting rights as the common units. As of February 17, 2004, there was one Class B unitholder.

      Related Transactions, and Director Independence.”

      Cash Distribution Policy

      We will distribute to our unitholders, on a quarterly basis, all of our available cash.cash in the manner described below. Available cash generally means, for any of our fiscal quarters,quarter ending prior to liquidation, all cash on hand at the end of thethat quarter less the amount of cash reserves that isare necessary or appropriate in the reasonable discretion of ourthe general partner to:

        •
        provide for the proper conduct of our business;

        •
        comply with applicable law, any of our debt instruments or other agreements; or

        •
        provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters.

      • provide for the proper conduct of our business;
      • comply with applicable law or any partnership debt instrument or other agreement; or
      • provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.

      In addition to distributions on its 2% general partner interest, 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, our general partner is entitled, without duplication and except for the agreed upon adjustment discussed below, to 15% of amounts we distribute in excess of $0.450 per unit, 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit.
      Upon closing of the Pacific acquisition, our general partner agreed to reduce the amounts due it as incentive distributions. The reduction will be effective for five years, as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. The total reduction in incentive distributions will be $65 million. The first quarterly reduction took place in connection with the distribution paid in February 2007.
      We paid $4.4$33.1 million to the general partner in incentive distributions in 2003. Our most recent2006. On February 14, 2007, we paid a quarterly distribution was $0.5625of $0.80 per unit.unit applicable to the fourth quarter of 2006. See Item 13. "Certain“Certain Relationships and Related Transactions—Transactions, and Director Independence — Our General Partner."

      ”

      Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operations — Liquidity and Capital Resources—Resources — Credit Facilities and Long-term Debt."”
      Issuer Purchases of Equity Securities
      We did not repurchase any of our common units during the fourth quarter of fiscal 2006.


      57

              See Item 12. "Security Ownership of Certain Beneficial Owners and Management and Related Unitholders' Matters" for equity compensation plan information.

      Item 6.    Selected Financial and Operating Data

      Item 6.Selected Financial Data
      The historical financial information below for Plains All American Pipeline, L.P. was derived from our audited consolidated financial statements as of December 31, 2006, 2005, 2004, 2003 2002, 2001, 2000 and 19992002 and for the years ended December 31, 2003, 2002, 2001, 2000 and 1999.then ended. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and Item 7. "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations."”
                           
        Year Ended December 31, 
        2006  2005  2004  2003  2002 
       
      Statement of operations data:
      		                    
      Total Revenues(1) $22,444.4  $31,176.5  $20,975.0  $12,589.7  $8,383.8 
      Crude oil and LPG purchases and related costs(1)  (20,819.7)  (29,691.9)  (19,870.9)  (11,746.4)  (7,741.2)
      Pipeline margin activities purchases(1)  (665.9)  (750.6)  (553.7)  (486.1)  (362.3)
      Field operating costs  (369.8)  (272.5)  (219.5)  (139.9)  (106.4)
      General and administrative expenses  (133.9)  (103.2)  (82.7)  (73.1)  (45.7)
      Depreciation and amortization  (100.4)  (83.5)  (68.7)  (46.2)  (34.0)
                           
      Total costs and expenses  (22,089.7)  (30,901.7)  (20,795.5)  (12,491.7)  (8,289.6)
                           
      Operating income  354.7   274.8   179.5   98.0   94.2 
      Interest expense  (85.6)  (59.4)  (46.7)  (35.2)  (29.1)
      Equity earnings in unconsolidated entities  7.7   1.8   0.5   0.2   0.4 
      Interest and other income (expense), net  2.3   0.6   (0.2)  (3.6)  (0.2)
      Income tax expense  (0.3)  —   —   —   — 
                           
      Income before cumulative effect of change in accounting principle(2) $278.8  $217.8  $133.1  $59.4  $65.3 
                           
      Basic net income before cumulative effect of change in accounting principle(2) $2.84  $2.77  $1.94  $1.01  $1.34 
                           
      Diluted net income before cumulative effect of change in accounting principle(2) $2.81  $2.72  $1.94  $1.00  $1.34 
                           
      Basic weighted average number of limited partner units outstanding  81.1   69.3   63.3   52.7   45.5 
      Diluted weighted average number of limited partner units outstanding  81.9   70.5   63.3   53.4   45.5 
      Balance sheet data (at end of period):
      		                    
      Total assets $8,714.9  $4,120.3  $3,160.4  $2,095.6  $1,666.6 
      Total long-term debt(3)  2,626.3   951.7   949.0   519.0   509.7 
      Total debt  3,627.5   1,330.1   1,124.5   646.3   609.0 
      Partners’ capital  2,976.8   1,330.7   1,070.2   746.7   511.6 
      Other data:
      		                    
      Maintenance capital expenditures $28.2  $14.0  $11.3  $7.6  $6.0 
      Net cash provided by (used in) operating activities(4)  (275.3)  24.1   104.0   115.3   185.0 
      Net cash (used in) investing activities(4)  (1,651.0)  (297.2)  (651.2)  (272.1)  (374.9)
      Net cash provided by financing activities  1,927.0   270.6   554.5   157.2   189.5 
      Declared distributions per limited partner unit(5)(6)  2.87   2.58   2.30   2.19   2.11 
      Volumes (thousands of barrels per day)(7)                    
      Transportation segment:                    
      Tariff activities  2,018   1,725   1,412   824   564 
      Pipeline margin activities  88   74   74   78   73 
                           
      Total  2,106   1,799   1,486   902   637 
                           


      58

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

      		 
      Statement of operations data:                
      Revenues $12,589.8 $8,384.2 $6,868.2 $6,641.2 $10,910.4 

      Cost of sales and field operations (excluding LTIP charge)
       
       
      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)  5.7  —  —  —  — 

      General and administrative expenses (excluding LTIP charge)
       
       
      50.0
       
       
      45.7
       
       
      46.6
       
       
      40.8
       
       
      23.2
       
      LTIP charge—general and administrative(1)  23.1  —  —  —  — 
      Depreciation and amortization  46.8  34.0  24.3  24.5  17.3 
      Restructuring expense  —  —  —  —  1.4 
        
      		 
      		 
      		 
      		 
      		 
      Total costs and expenses  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  98.2  94.6  72.4  110.6  (81.6)
      Interest expense  (35.2) (29.1) (29.1) (28.7) (21.1)
      Interest income and other, net(2)  (3.6) (0.2) 0.4  (4.4) 0.9 
        
      		 
      		 
      		 
      		 
      		 
      Income (loss) from continuing operations before cumulative effect of accounting change $59.4 $65.3 $43.7 $77.5 $(101.8)
        
      		 
      		 
      		 
      		 
      		 

      Basic net income (loss) per limited partner unit before cumulative effect of accounting change
       
      $
      1.01
       
      $
      1.34
       
      $
      1.12
       
      $
      2.64
       
      $
      (3.16
      )

      Diluted net income (loss) per limited partner unit before cumulative effect of accounting change
       
      $
      1.00
       
      $
      1.34
       
      $
      1.12
       
      $
      2.64
       
      $
      (3.16
      )

      Basic weighted average number of limited partner units outstanding
       
       
      52.7
       
       
      45.5
       
       
      37.5
       
       
      34.4
       
       
      31.6
       

      Diluted weighted average number of limited partner units outstanding
       
       
      53.4
       
       
      45.5
       
       
      37.5
       
       
      34.4
       
       
      31.6
       

      Table continued on following page.

       
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       


                           
        Year Ended December 31, 
        2006  2005  2004  2003  2002 
       
      Facilities Segment:                    
      Crude oil, refined products and LPG storage (average monthly capacity in millions of barrels)  20.7   16.8   14.8   12.0   3.8 
                           
      Natural gas storage, net to our 50% interest (average monthly capacity in billions of cubic feet)  12.9   4.3   —   —   — 
      LPG processing (thousands of barrels per day)  12.2   —   —   —   — 
      Total (average monthly capacity in millions of barrels)(8)  23.2   17.5   14.8   12.1   3.9 
      Marketing segment:                    
      Crude oil lease gathering  650   610   589   437   410 
      LPG sales  70   56   48   38   35 
      Waterborne foreign crude imported  63   59   12   N/A   N/A 
                           
      Total  783   725   649   475   445 
                           
      (1)Includes buy/sell transactions for all periods prior to the second quarter of 2006. See Note 2 to our Consolidated Financial Statements.
      (2)Income from continuing operations before cumulative effect of change in accounting principle pro forma for the impact of the January 1, 2006 change in our method of accounting for unit-based payment transactions would have been $224.1 million, $136.3 million, $65.7 million, and $71.6 million for 2005, 2004, 2003 and 2002, respectively. In addition, basic net income per limited partner unit before cumulative effect of change in accounting principle would have been $2.81 ($2.76 diluted), $1.98 ($1.98 diluted), $1.13 ($1.12 diluted) and $1.47 ($1.47 diluted) for 2005, 2004, 2003 and 2002, respectively. Income from continuing operations before cumulative effect of change in accounting principle pro forma for the impact of the January 1, 2004 change in our method of accounting for pipeline linefill in third-party assets would have been $61.4 million and $64.8 million for 2003 and 2002, 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) and $1.33 ($1.33 diluted) for 2003 and 2002, respectively.
      (3)Includes current maturities of long-term debt of $9.0 million at December 31, 2002 classified as long-term because of our ability and intent to refinance these amounts under our long-term revolving credit facilities.
      (4)In conjunction with the change in accounting principle we adopted as of January 1, 2004, we have reclassified cash flows for 2003 and prior years 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.
      (5)Distributions represent those declared and paid in the applicable year.
      (6)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 5 to our Consolidated Financial Statements.
      (7)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 year.
      (8)Calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to crude oil barrel ratio; and (iii) LPG processing volumes multiplied by the number of days in the month and divided by 1,000 to convert to monthly volumes in millions.

      59

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


      Balance sheet data (at end of period):
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       
      Working capital surplus (deficit) $(68.9)$(34.3)$52.9 $47.1 $101.5
      Total assets  2,095.6  1,666.6  1,261.2  885.8  1,223.0
      Total long-term debt(3)(4)  519.0  509.7  354.7  320.0  424.1
      Total debt(4)  646.2  609.0  456.2  321.3  482.8
      Partners' capital  746.7  511.6  402.8  214.0  193.0

       

       
      Year Ended December 31,

       
       
      		 2003
      		 2002
      		 2001
      		 2000
      		 1999
      		 
      Other data (in millions):                
      Maintenance capital expenditures $7.6 $6.0 $3.4 $1.8 $1.7 
      Net cash provided by (used in) operating activities  68.5  173.9  (30.0) (33.5) (71.2)
      Net cash provided by (used in) investing activities  (225.3) (363.8) (249.5) 211.0  (186.1)
      Net cash provided by (used in) financing activities  157.2  189.5  279.5  (227.8) 305.6 
      Declared distributions per limited partner unit(5)(6)(7)  2.19  2.11  1.95  1.83  1.59 

      Operating Data:
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       
       Volumes (thousands of barrels per day, unless otherwise noted)(8):                
       Pipeline segment:                
        Tariff activities                
         All American  59  65  69  74  103 
         Basin  263  93  N/A  N/A  N/A 
         Other domestic(9)  299  219  144  130  61 
         Canada  203  187  132  N/A  N/A 
        Pipeline margin activities  78  73  61  60  54 
        
      		 
      		 
      		 
      		 
      		 
         Total  902  637  406  264  218 
        
      		 
      		 
      		 
      		 
      		 
       Gathering, marketing, terminalling and storage segment:                
        Lease gathering  437  410  348  262  265 
        Bulk purchases(10)  90  68  46  28  138 
        
      		 
      		 
      		 
      		 
      		 
         Total  527  478  394  290  403 
        
      		 
      		 
      		 
      		 
      		 
        LPG sales  38  35  19  N/A  N/A 
        
      		 
      		 
      		 
      		 
      		 
      (1)
      Compensation expense related to our Long Term Incentive Plan ("LTIP"), see Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations—Vesting of Restricted Units under Long-Term Incentive Plan."

      (2)
      The 2000 period includes $15.1 million related to a loss on 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.

      (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.

      Table continued on following page.


      (5)
      Distributions represent those declared and paid in the applicable period.

      (6)
      No distributions were declared or paid on subordinated units in the first quarter of 2000. A distribution of $0.45/unit was declared and paid to holders of common units in that period.

      (7)
      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."

      (8)
      Volumes associated with acquisition represent total volumes transported for the number of days we actually owned the assets divided by the number of days in the period.

      (9)
      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.

      (10)
      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.
      Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

      Item 7.    

      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. For more detailed information regarding the basis of presentation for the following financial information, see the "Notes to the Consolidated Financial Statements."
      Our discussion and analysis includes the following:

      • Executive Summary
      • Acquisitions and Internal Growth Projects
      • Critical Accounting Policies and Estimates
      • Recent Accounting Pronouncements and Change in Accounting Principle
      • Results of Operations
      • Outlook
      • Liquidity and Capital Resources
      • Off-Balance Sheet Arrangements
      Executive Summary
      Company Overview
      We are engaged in the transportation, storage, terminalling and marketing of Businesscrude oil, refined products and 2003 Results

      •
      Acquisition Activities

      •
      Critical Accounting Policiesliquefied petroleum gas and Estimates

      •
      Results of Operations

      •
      Outlook

      •
      Liquidityother natural gas related petroleum products (liquefied petroleum gas and Capital Resources

      Overview of Businessother natural gas related petroleum products are collectively referred to as “LPG”). In addition, through our 50% equity ownership in PAA/Vulcan, we develop and 2003 Results

      Company Overview—Plains All American Pipeline, L.P. is a Delaware limited partnership (the "Partnership")operate natural gas storage facilities. We were formed in September of 1998. See Items 11998, and 2. "Business and Properties—Organizational History." Ourour operations are conducted directly and indirectly through our operating subsidiaries, Plains Marketing, L.P.subsidiaries.

      Prior to the fourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business (most notably in conjunction with the Pacific acquisition), Plains Pipeline, L.P.we have revised the manner in which we internally evaluate our segment performance and Plains Marketing Canada, L.P. We are engaged in interstatedecide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and intrastate(iii) Marketing. Our transportation segment operations generally consist of fee-based activities associated with transporting crude oil and refined products on pipelines and gathering systems. We generate revenue through a combination of tariffs, third-party leases of pipeline capacity, transportation fees, barrel exchanges and buy/sell arrangements. Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, gathering,refined products and LPG, as well as LPG fractionation and isomerization services. We generate revenue through a combination ofmonth-to-month and multi-year leases and processing arrangements. Our marketing segment operations generally consist of merchant activities associated primarily with the purchase and sale of crude oil and LPG. Our marketing activities are designed to produce a stable baseline of results in a variety of market conditions, while at the same time providing upside exposure to opportunities inherent in volatile market conditions. These activities utilize storage facilities at major interchange and terminalling locations and various hedging strategies to reduce the negative impact of market volatility and provide counter-cyclical balance.
      Overview of Operating Results, Capital Spending and Significant Activities
      During 2006, we recognized net income of $285.1 million and earnings per diluted limited partner unit of $2.88, compared to net income of $217.8 million and earnings per diluted limited partner unit of $2.72 during 2005.


      60

      Both 2006 and 2005 were substantial increases over 2004. Net income was $130.0 million and earnings per diluted limited partner unit was $1.89 for 2004. Key items impacting 2006 include:
      Balance Sheet and Capital Structure
      • The completion of the Pacific acquisition for approximately $2.5 billion (including the equity issuance and assumption of debt discussed below), and six other acquisitions for aggregate consideration of approximately $565 million.
      • The issuance of 22 million limited partner units (valued at $1.0 billion) in exchange for Pacific limited partner units as part of the Pacific acquisition and the sale of 13.4 million limited partner units for net proceeds of approximately $621 million.
      • The assumption of $433 million of senior notes as part of the Pacific acquisition and the issuance of $1,250 million of Senior Notes for net proceeds of approximately $1,243 million.
      • Capital expenditures (excluding acquisitions and maintenance capital) of $332 million.
      • Limited partner distributions of $224.9 million ($2.87 per limited partner unit) and General Partner distributions of $37.7 million paid during 2006.
      Income Statement
      • Favorable execution of our risk management strategies in our marketing segment in a pronounced contango market with a high level of overall crude oil volatility.
      • Increased volumes and related tariff revenues on our pipeline systems.
      • An increase in field operating costs and general and administrative expenses primarily associated with continued growth from acquisitions as well as internal growth projects and an increase of $17 million in 2006 related to our Long-Term Incentive Plans. See “— Critical Accounting Policies and Estimates — Critical Accounting Estimates — Long-Term Incentive Plan Accruals.”
      • A charge of approximately $4 million in 2006 resulting from themark-to-market of open derivative instruments pursuant to SFAS 133.
      • A gain of approximately $6 million resulting from the reduction of our obligation for outstanding LTIP awards, which was recorded as a cumulative effect of change in accounting principle pursuant to the adoption of SFAS No. 123(R) (revised 2004), “Share-Based Payment.”
      Prospects for the Future
      Access to storage tankage by our marketing segment provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow associated with this segment. The strategic use of our terminalling and storage assets in conjunction with our gathering and marketing operations generally provides us with the flexibility to maintain a base level of margin irrespective of crude oil market conditions and, in certain circumstances, to realize incremental margin during volatile market conditions.
      During 2006, we strengthened our business by expanding our asset base through approximately $3 billion of acquisitions and $332 million of internal growth projects. In 2007, we intend to spend approximately $500 million on internal growth projects and also to continue to develop our inventory of projects for implementation beyond 2007. Several of the larger storage tank projects for 2007, such as the construction or expansion of the Patoka, Cushing and St. James terminals, are well positioned to benefit from the importation of waterborne foreign crude oil into the Gulf Coast as well as the marketingimportation of Canadian crude oil. We also believe there are opportunities for us to grow our LPG business. In addition, our 2005 entry into the natural gas storage business and our 2006 entries into the refined products transportation and storage of liquefied petroleum gas and other petroleum products. We refer to liquified petroleum gas and other petroleum products collectively as "LPG." We own an extensive network in the United States and Canada of pipeline transportation, terminalling, storage and gathering assets in key oil producing basins and at major market hubs.

              We are one of the largest midstream crude oil companies in North America, with approximately 7,000 miles of crude oil pipelines, approximately 24 million barrels of terminalling and storage capacity and a full complement of truck transportation and injection assets. On average, we handle over 1.6 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 are conducted primarily in Texas, Oklahoma, California, Louisianabusiness and the Canadian provincesbarge transportation business are consistent with our stated strategy of Alberta and Saskatchewan and consist of two operating segments: (i) pipeline operations and (ii) gathering, marketing, terminalling and storage operations ("G M T& S"). Throughleveraging our pipeline segment, we engage in interstate and intrastate crude oil pipeline transportation and certain related margin activities. Through our G M T & 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.

      Industry and Market Overview—Crude oil market conditions during 2003 were extremely volatile as a confluence of several events caused the NYMEX benchmark price of crude oil to fluctuate widely. In addition, the crude oil market was in steep backwardation (prices for future deliveries were lower than prices for current deliveries) for much of the year. Crude oil production in the U.S. Midwest continues to decline while refinery demand remains stable to increasing. Generally, incremental barrels to this region must come from the south through Cushing or the Capline Pipeline System or from Canada to the north.

              We anticipate that medium to long-term market dynamics in the crude oil industry will shift in a manner that will complement our asset base andassets, business model, which is designed to deliver stable results in cyclicalknowledge and volatile markets. We expect to see an increasingly more volatile marketexpertise into businesses that will



      be subject to more frequent short-term swings in market prices and shifts in market structure. We believe these price swings and shifts in market structure could be much more pronounced than we have seen in the 20 or so years since crude oil was deregulated and began trading on the NYMEX. In addition, we anticipate that the crude oil supply and demand imbalance in the U.S. Midwest mentioned above will continue to intensify.

      2003 Operating Results Overview—During 2003:


      61

      business model to the refined products business by establishing and growing a marketing and distribution business to complement our G M T& S segment, including the impact of the charges discussed above. This growth was primarily driven by (i) the impact of the current year acquisitions subsequent to their acquisition during 2003 and the inclusion of a full year contribution from those assets that we acquired during 2002 coupled with (ii) the positive results in volatile market conditions of our counter-cyclically balanced activities in our G M T & S segment.

      •
      We raised our distribution level on our limited partner units on two separate occasions by a total of $0.10 per unit to $2.25 per unit on an annualized basis

      Prospects for the Future—strategically located assets. We believe we have access to equity and debt capital and that 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 oilmidstream 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 2003 we further strengthened our position by expanding our asset base through acquisition and internal growth projects. We will continue to pursue the purchase of midstream crude oil 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 oilmidstream infrastructure, we face various operational, regulatory and financial challenges that may impact our



      ability to execute our strategy as planned. In addition, we operate in a mature industry and believe that acquisitions will play an important role in our potential growth. We will continue to pursue the purchase of midstream assets, and we will also continue to initiate expansion projects designed to optimize product flows in the areas in which we operate. However, we can give no assurance that our current or future acquisition or expansion efforts will be successful. See "—RiskItem 1A. “Risk Factors — Risks Related to Our Business" for further discussion of these items.

      Business.”

      Acquisitions and Internal Growth Projects

      We completed a number of acquisitions and capital expansion projects in 2003, 20022006, 2005 and 20012004 that have impacted theour results of operations and enabled us to enhance our liquidity, as discussed herein. The following table summarizes our capital expenditures for acquisitions were accounted(including equity investments), capital expansion (internal growth projects) and maintenance capital for the periods indicated (in millions):
                   
        December 31, 
        2006  2005  2004 
       
      Acquisition capital(1) $3,021.1  $40.3  $563.9 
      Investment in PAA/Vulcan Gas Storage, LLC  10.0   112.5   — 
      Investment in Settoon Towing  33.6   —   — 
      Internal growth projects  332.0   148.8   117.3 
      Maintenance capital  28.2   14.0   11.3 
                   
        $3,424.9  $315.6  $692.5 
                   
      (1)Acquisition capital includes deposits in the year the acquisition closed, rather than the year the deposit was paid. Deposits paid were approximately $12 million for the Shell Gulf Coast Pipeline Systems acquisition in 2004.


      62

      Internal Growth Projects
      As a result of capital expansion opportunities originating from prior acquisitions, we increased our annual level of spending on these projects by 123% in 2006 compared to 2005. The following table summarizes our 2006 and 2005 projects (in millions):
               
      Projects
      		 2006  2005 
       
      St. James, Louisiana storage facility — Phase I $69.9  $15.2 
      St. James, Louisiana storage facility — Phase II  12.9   — 
      Trenton pipeline expansion  12.3   31.8 
      Kerrobert tankage  28.5   4.3 
      East Texas/Louisiana tankage  12.0   — 
      Spraberry System expansion  15.4   — 
      Cushing Phase IV and V expansions  1.1   11.2 
      Cushing Tankage — Phase VI  10.1   — 
      Cushing to Broome pipeline  —   8.2 
      Northwest Alberta fractionator  2.2   15.6 
      Link acquisition asset upgrades  —   9.3 
      High Prairie rail terminals  9.1   — 
      Midale/Regina truck terminal  12.7   — 
      Truck trailers  9.9   — 
      Wichita Falls tankage  7.8   — 
      Basin connection — Oklahoma  6.9   — 
      Mobile/Ten Mile tankage and metering  4.0   — 
      Cheyenne Pipeline Construction  10.3   — 
      Other Projects  106.9   53.2 
               
      Total $332.0  $148.8 
               
      Our 2006 projects included the purchase price was allocated, in accordance with the purchase methodconstruction and expansion of accounting.pipeline systems and crude oil storage and terminal facilities (notably Cushing and St. James). 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 discussedexpect internal growth capital projects to expand further in "Liquidity2007. See “— Liquidity and Capital Resources" below.

      2003 Acquisitions

              During 2003, we completed ten acquisitions for aggregate consideration

      Acquisitions are financed using a combination of approximately $159.5 million. The aggregate consideration includes cash paid, estimated transaction costs, assumed liabilitiesequity and estimated near-term capital costs. The acquisitions were initially financed withdebt, including 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 tocommencing on the effective date of each acquisition as indicated in the table below. TheseOur ongoing acquisitions and capital expansion activities are discussed further in “— Liquidity and Capital Resources.” See Note 3 to our Consolidated Financial Statements for additional information about our acquisition activities.


      63

      2006 Acquisitions
      In 2006, we completed several acquisitions for aggregate consideration of approximately $3.0 billion. The Pacific merger was material to our operations. See Note 3 to our Consolidated Financial Statements. The following table summarizes the acquisitions that were completed in 2006, and a description of our material acquisitions follows the table (in millions):
               
        Effective
      		 Acquisition
      		   
      Acquisition
      		 Date Price  Operating Segment
       
      Pacific 11/15/2006 $2,455.7  Transportation, Facilities,
      Marketing
      Andrews 4/18/2006  220.1  Transportation
      Facilities, Marketing
      SemCrude 5/1/2006  129.4  Marketing
      BOA/CAM/HIPS 7/31/2006  130.2  Transportation
      Products Pipeline 9/1/2006  65.6  Transportation
      Other various  20.1  Transportation, Facilities,
      Marketing
               
      Total   $3,021.1   
               
      Pacific.  On November 15, 2006 we completed our acquisition of Pacific pursuant to an Agreement and Plan of Merger dated June 11, 2006. The merger-related transactions included: (i) the acquisition from LB Pacific of the general partner interest and incentive distribution rights of Pacific as well as approximately 5.2 million Pacific common units and approximately 5.2 million Pacific subordinated units for a total of $700 million and (ii) the acquisition of the balance of Pacific’s equity through aunit-for-unit exchange in which each Pacific unitholder (other than LB Pacific) received 0.77 newly issued common units of the Partnership for each Pacific common unit. The total value of the transaction was approximately $2.5 billion, including the assumption of debt and estimated transaction costs. Upon completion of the merger-related transactions, the general partner and limited partner ownership interests in Pacific were extinguished and Pacific was merged with and into the Partnership. The assets acquired in the Pacific acquisition included mainlineapproximately 4,500 miles of active crude oil pipeline and gathering systems and 550 miles of refined products pipelines, over 13 million barrels of active crude oil gathering lines, terminalstorage capacity and 9 million barrels of refined products storage facilities,capacity, a fleet of approximately 75 owned or leased trucks and an underground LPG storage facility. With the exceptionapproximately 1.9 million barrels of $0.5 million that was allocated to goodwill and other intangible assets and $4.7 million associated with crude oil and refined products linefill and working inventory, the remaining aggregate purchase price was allocated to property and equipment.inventory. 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 05/05/03  2.9 Pipeline
      South Louisiana Assets(1) 06/01/03  13.4 Pipeline/G,M,T,&S
      Alto Storage Facility 06/01/03  8.5 G,M,T&S
      Iraan to Midland Pipeline System 06/30/03  17.6 Pipeline
      ArkLaTex Pipeline System 10/01/03  21.3 Pipeline
      South Saskatchewan Pipeline System 11/01/03  47.7 Pipeline
      Atchafalaya Pipeline System(2) 12/01/03  4.4 Pipeline
          
      		  
      Total 2003 Acquisitions   $159.5  
      (1)
      Includes a 33.3% interest in Atchafalaya Pipeline L.L.C.

      (2)
      Includes two acquisitions each for 33.3% interests in Atchafalaya Pipeline L.L.C.

              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 8.9 million barrels (net to our interest) of above-ground crude oil terminalling and storage assets in West Texas from Shell Pipeline Company LP and Equilon Enterprises LLC (the "Shell acquisition") for approximately $324 million. 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 oil producing regions in the United States, dating back to the 1930s. The acquiredPacific assets complement our existing asset infrastructurebase in West TexasCalifornia, the Rocky Mountains and represent a transportation link to Cushing, Oklahoma, where we provide storageCanada, with minimal asset overlap but attractive potential vertical integration opportunities. The results of operations and terminalling services. In addition, we believe thatassets and liabilities from the Basin Pipeline System is poised to benefit from potential shut-downs of refineries and other pipelines due to the shifting market dynamicsPacific acquisition have been included in the West Texas area. The Rancho Pipeline System was taken out of service in March 2003, pursuant to the operating agreement. See Items 1 and 2. "Business and Properties—Acquisitions and Dispositions—Shutdown and Partial Sale of Rancho Pipeline System."

              For more information on this transaction, as well as historicalour consolidated financial information on the businesses acquired and pro forma financial information reflecting the acquisition of the businesses, please refer to our Form 8-K dated August 9, 2002, which was filed with the Securities and Exchange Commission.

              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. As of December 31, 2003, we determined that it was beyond a reasonable doubt that the performance standards were met and we recorded additional consideration of $24.3 million, (see Note 7—"Partners' Capital and Distributions" in the "Notes to the Consolidated Financial Statements"), resulting in aggregate consideration of approximately $73.9 million. The deferred consideration was recorded as goodwill.

              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.statements since November 15, 2006. The purchase price as adjusted post-closing,allocation related to the Pacific acquisition is preliminary and subject to change. See Note 3 to our Consolidated Financial Statements.

      The purchase price 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
        
           
      Cash payment to LB Pacific $700.0 
      Value of Plains common units issued in exchange for Pacific common units  1,001.6 
      Assumption of Pacific debt (at fair value)  723.8 
      Estimated transaction costs(1)  30.3 
           
      Total purchase price $2,455.7 
           
      (1)Includes investment banking fees, costs associated with a severance plan in conjunction with the acquisition and various other direct acquisition costs.


      64

           
           
           
      Purchase Price Allocation
      		    
      Property, plant and equipment, net $1,411.7 
      Investment in Frontier  8.7 
      Inventory  32.6 
      Pipeline linefill and inventory in third party assets  63.6 
      Intangible assets  72.3 
      Goodwill(1)  843.2 
      Assumption of working capital and other long-term assets and liabilities, including $20.0 of cash  23.6 
           
      Total purchase price $2,455.7 
           
      (1)Represents the preliminary amount in excess of the fair value of the net assets acquired and is associated with our view of the future results of operations of the businesses acquired based on the strategic location of the assets and the growth opportunities that we expect to realize as we integrate these assets into our existing business strategy.
      The majority of the acquisition costs associated with the Pacific acquisition was incurred as of December 31, 2006, resulting in total cash paid during 2006 of approximately $723 million.
      The following table shows our calculation of the sources of funding for the acquisition (in millions):
           
      Fair value of Plains common units issued in exchange for Pacific common units $1,001.6 
      Plains general partner capital contribution  21.6 
      Assumption of Pacific debt (at estimated fair value), net of repayment of Pacific credit facility(1)  433.1 
      Plains new debt incurred  999.4 
           
      Total sources of funding $2,455.7 
           
      (1)The assumption of Pacific’s debt and credit facility at fair value was $433.1 million and $290.7 million, respectively. We paid off the credit facility in connection with closing of the transaction.
              Murphy Oil Company Ltd. Midstream Operations.Other 2006 Acquisitions.    In May 2001,  During 2006, we completed the acquisitionsix additional acquisitions for aggregate consideration of substantially allapproximately $565 million. These acquisitions included (i) 100% of the Canadianequity interests of Andrews Petroleum and Lone Star Trucking, which provide isomerization, fractionation, marketing and transportation services to producers and customers of natural gas liquids (collectively, the “Andrews acquisition”), (ii) crude oil gathering and transportation assets and related contracts in South Louisiana (SemCrude), (iii) interests in various crude oil pipeline gathering, storagesystems in Canada and terminalling assets of Murphy Oil Company Ltd.the U.S. including a 100% interest in the BOA Pipeline, various interests in HIPS and a 64.35% interest in the CAM Pipeline system, and (iv) three refined products pipeline systems.
      In addition, in November 2006, we purchased a 50% interest in Settoon Towing for approximately $158.4 million$33 million. Settoon Towing owns and operates a fleet of 57 transport and storage barges as well as 30 transport tugs. Its core business is the gathering and transportation of crude oil and produced water from inland production facilities across the Gulf Coast.

      65

      2005 Acquisitions
      We completed six small transactions in cash after post-closing adjustments, including financing2005 for aggregate consideration of approximately $40.3 million. The transactions included crude oil trucking operations and transaction costs (the "Murphy acquisition"). Initial financing forseveral crude oil pipeline systems along the



      acquisition was provided through borrowings under Gulf Coast as well as in Canada. We also acquired an LPG pipeline and terminal in Oklahoma. These acquisitions did not materially impact our credit facilities. The purchase price included $6.5 million for excess inventoryresults of operations, either individually or in the pipeline systems.aggregate. The following table summarizes our acquisitions that were completed in 2005 (in millions):

                 
        Effective
      		  Acquisition
      		   
      Acquisition
      		 Date  Price  Operating Segment
       
      Shell Gulf Coast Pipeline Systems(1)  1/1/2005  $12.0  Transportation
      Tulsa LPG Pipeline  3/2/2005   10.0  Marketing
      Other acquisitions  Various   18.3  Transportation, Facilities,
      Marketing
                 
      Total     $40.3   
                 
      (1)A $12 million deposit for the Shell Gulf Coast Pipeline Systems acquisition was paid into escrow in December 2004.
      In addition, in September 2005, PAA/Vulcan acquired Energy Center Investments LLC (“ECI”), an indirect subsidiary of Sempra Energy, for approximately $250 million. ECI develops and operates underground natural gas storage facilities. We own 50% of PAA/Vulcan and the remaining 50% is owned by a subsidiary of Vulcan Capital. We made a $112.5 million capital contribution to PAA/Vulcan and we account for the investment in PAA/Vulcan under the equity method in accordance with Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
      2004 Acquisitions
      In 2004, we completed several acquisitions for aggregate consideration of approximately $563.9 million. The Link and Capline acquisitions were material to our operations. See Note 3 to our Consolidated Financial Statements. The following table summarizes our acquisitions that were completed in 2004, and a description of our material acquisitions follows the table (in millions):
                 
        Effective
      		  Acquisition
      		   
      Acquisition
      		 Date  Price  Operating Segment
       
      Capline and Capwood Pipeline Systems (“Capline acquisition”)(1)  03/01/04  $158.5  Transportation
      Link Energy LLC (“Link acquisition”)  04/01/04   332.3  Transportation, Facilities,
      Marketing
      Cal Ven Pipeline System  05/01/04   19.0  Transportation
      Schaefferstown Propane Storage Facility(2)  08/25/04   46.4  Facilities
      Other  various   7.7  Facilities, Marketing
                 
      Total     $563.9   
                 
      (1)Includes a deposit of approximately $16 million which was paid in December 2003 for the Capline acquisition.
      (2)Includes approximately $14.4 million of LPG operating inventory acquired.
      Capline and Capwood Pipeline Systems.  The principal assets acquired includeare: (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 a633-mile,40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a58-mile,20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. 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.


      66

      Link Energy LLC.  The Link crude oil business we acquired consisted of approximately 5607,000 miles of active crude oil pipeline and condensate mainlines (including dual lines on which condensate is shipped for blending purposesgathering systems, over 10 million barrels of active crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and blended crude is shipped in the opposite direction) and associated gathering and lateral lines, approximately 1.12 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 254,000 barrels of pipeline linefill and tank inventories,working inventory. The Link assets complement our assets in West Texas and 121 trailers used primarily for crude oil transportation. The acquired assets are part ofalong the Gulf Coast and allow us to expand our strategy to establish a Canadian operation that complements our operationspresence 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, mediumRocky Mountain and heavy crudes, as well as condensate.

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

      Oklahoma/Kansas regions.
      Crude oil pipeline, gathering and terminal assets $148.0
      Pipeline linefill  7.6
      Net working 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

              Our

      Critical Accounting Policies
      We have adopted various accounting policies to prepare our consolidated financial statements in accordance with generally accepted accounting principles in the United States. These critical accounting policies are discussed in Note 2 to the Consolidated Financial Statements beginning on page F-8. Statements.
      Critical Accounting 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.

      Purchase and Sales AccrualsAccruals.

        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-partythird 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 basis. In addition, we estimate that less than 4% of total operating income and quarterly basis.less than 5% of total net income are recorded using estimates. 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.

      Mark-to-Market Accrual Accrual.

        In situations where we are required to make mark-to-market estimates derivatives 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 annual 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.

      Contingent Liability AccrualsAccruals.

        We accrue reserves for contingent liabilities including, but not limited to, environmental remediation and governmental penalties, insurance claims, asset retirement obligations, taxes, 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


      67

      necessary regulatory approvals for, and potential modification of, our environmental 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'sworker’s compensation and employee health insurance claims, and the possibility of existing legal claims giving rise to additional claims. Our estimates for 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 for the contingent liabilities discussed above would have an approximate $1.0$5.2 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.

      Employee Incentive Plan Accrual

              We also make accruals for potential payments under our Long-Term Incentive Plan ("LTIP") when we determine that vesting of the common units granted under the LTIP is probable. The aggregate amount of the actual charge to expense will be determined by the unit price on the date vesting occurs (or, in some cases, the average unit price for a range of dates) multiplied by the number of units, plus our share of associated employment taxes. Uncertainties involved in this accrual include whether or not we actually achieve the specified performance requirements, the actual unit price at time of settlement and the continued employment of personnel subject to the vestings. A change in our unit price of $1 from the amount we used to record our accrual would have an impact of approximately $0.8 million on our operating income. 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.

      Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible AssetsAssets.

        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'smanagement’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'smanagement’s assessment of the value of the assets acquired and, to the extent available, third party assessments. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. 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. The purchase price allocation related to the Pacific acquisition is preliminary and subject to change. See Note 3 to our Consolidated Financial Statements.

      Long-Term Incentive Plan Accruals.  We also make accruals to recognize the fair value of our outstanding LTIP awards as compensation expense. Under generally accepted accounting principles, we are required to estimate the fair value of our outstanding LTIP awards and recognize that fair value as compensation expense over the course of the LTIP award’s vesting period. For LTIP awards that contain a performance condition, the fair value of the LTIP award is recognized as compensation expense only if the attainment of the performance condition is considered probable. The amount of the actual charge to compensation expense will be determined by the unit price on the date vesting occurs (or, in some cases, the average unit price for a range of dates preceding the vesting date) multiplied by the number of units, plus our share of associated employment taxes. Uncertainties involved in this estimate include the actual unit price at time of settlement, whether or not a performance condition will be attained and the continued employment of personnel subject to the vestings.
      We achieved a $3.20 annualized distribution rate and therefore we are accruing compensation expense for LTIP awards that vest upon the attainment of that rate. We recognized total compensation expense of approximately $42.7 million in 2006 and $26.1 million in 2005 related to awards granted under our various LTIP plans. We cannot provide assurance that the actual fair value of our LTIP awards will not vary significantly from estimated amounts. See Note 10 to our Consolidated Financial Statements.
      Goodwill.  We perform our goodwill impairment test annually (as of June 30) and when events or changes in circumstances indicate that the carrying value may not be recoverable. We consider the estimate of fair value to be a critical accounting estimate because (a) a goodwill impairment could have a material impact on our financial position and results of operations and (b) the estimate is based on a number of highly subjective judgments and assumptions.
      Property, Plant and Equipment and Depreciation Expense.  We compute depreciation using the straight-line method based on estimated useful lives. We periodically evaluate property, plant and equipment for impairment


      68

      when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property, plant and equipment a critical accounting estimate. In determining the existence of an impairment in carrying value, we make a number of subjective assumptions as to:
      • whether there is an indication of impairment;
      • the grouping of assets;
      • the intention of “holding” versus “selling” an asset;
      • the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
      • if an impairment exists, the fair value of the asset or asset group.
      Asset Retirement Obligation
      We account for asset retirement obligations under SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (1) the time of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense and (4) subsequent measurement of the liability. SFAS 143 requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.
      Some of our assets, primarily related to our transportation segment, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. The timing of the obligations is determined relative to the date on which the asset is abandoned.
      Many of our pipelines are trunk and interstate systems that transport crude oil. The pipelines with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demands for this transportation will cease and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates. A small portion of our contractual or regulatory obligations are related to assets that are inactive or that we plan to take out of service and although the ultimate timing and costs to settle these obligations are not known with certainty, we can reasonably estimate the obligation.
      Recent Accounting Pronouncements and Change in Accounting Principle
      Recent Accounting Pronouncements
      For a discussion of recent accounting pronouncements that will impact us, see Note 2 to our Consolidated Financial Statements.
      Changes in Accounting Principle
      Stock-Based Compensation
      In December 2004, SFAS 123(R) was issued, which amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from such share-based payment transactions be recognized in the financial statements at fair value. Following our general partner’s adoption of Emerging Issues Task Force IssueNo. 04-05, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” we are now part of the same consolidated group and thus SFAS 123(R) is applicable to our general partner’s long-term incentive plan. We


      69

      adopted SFAS 123(R) on January 1, 2006 under the modified prospective transition method, as defined in SFAS 123(R), and recognized a cumulative effect of change in accounting principle of approximately $6 million. The cumulative effect adjustment represents a decrease to our LTIPlife-to-date accrued expense and related liability under our previous cash-plan, probability-based accounting model and adjusts our aggregate liability to the appropriate fair-value based liability as calculated under a SFAS 123(R) methodology. Our LTIPs are administered by our general partner. We are required to reimburse all costs incurred by our general partner through LTIP settlements. As a result, our LTIP awards are classified as liabilities under SFAS 123(R). Under the modified prospective transition method, we are not required to adjust our prior period financial statements for our LTIP awards.
      Linefill
      During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third party assets. Historically, we 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 did not include linefill barrels in the same average costing calculation as our operating inventory, but instead carried linefill at historical cost. Following this change in accounting principle, the linefill in third party assets that we historically classified as a portion of Pipeline Linefill on the face of the balance sheet (a long-term asset) and carried at historical cost, is 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 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 on the consolidated balance sheet.
      This change in accounting principle was effective January 1, 2004 and is reflected as a cumulative change in our consolidated statement of operations for the year ended December 31, 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 in Third-Party Assets of $28.9 million.
      Results of Operations

      Analysis of Operating Segments

      Prior to the fourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business most notably in conjunction with the Pacific acquisition, we have revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. As a result, we now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, and (iii) Marketing. Prior period disclosures have been revised to reflect our change in segments.
      We evaluate segment performance based on (i) segment profit and (ii) maintenance capital. We define segment profit as revenues less (i) purchases and related costs, (ii) field operating costs and (iii) segment general and administrative ("(“G&A"&A”) expenses. Each of the items above excludes depreciation and amortization. As a master limited partnership, we make quarterly distributions of our "Available Cash"“available cash” (as defined in our Partnership Agreement)partnership agreement) to our unitholders. Therefore, we look at each period'speriod’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 keepmitigate the actual decline in the value of our principal fixed assets from declining.assets. 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, which is deducted in determining “available cash,” 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 considered expansion capital expenditures,


      70

      not considered maintenance capital expenditures.capital. 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. See Note 15 "Operating Segments" in the "Notes to theour Consolidated Financial Statements"Statements for a reconciliation of segment profit to net income. The following table reflects our resultsconsolidated income before cumulative effect of operations and maintenance

      change in accounting principle.

      capital for each

      Our segment (note that eachanalysis involves an element of the items in the following table excludes depreciation and amortization).

       
      		 Pipeline
      Operations
      		 Gathering,
      Marketing,
      Terminalling &
      Storage
      Operations
      		 
       
      		 (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 expensesjudgment relating to the allocations between segments. In connection with its operations, the marketing segment secures transportation and facilities services from the Partnership’s other two segments as well as third-party service providers undermonth-to-month and multi-year arrangements. Inter-segment transportation service rates are based on posted tariffs for pipeline transportation services. Facilities segment services are also obtained at rates consistent with rates charged to third parties for similar services; however, certain terminalling and storage rates are discounted to our marketing segment to reflect the business activitiesfact that existed atthese services may be canceled on short notice to enable the facilities segment to provide services to third parties. We believe that time. The proportionalthe estimates with respect to the rates that are charged by our facilities segment to our marketing segment are reasonable. We also allocate certain operating expense and general and administrative overheads between segments. We believe that the estimates with respect to the allocations by segment require judgement 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.
      reasonable.

      Pipeline OperationsTransportation

      As of December 31, 2003,2006, we owned and operated approximately 7,00020,000 miles of active gathering and mainline crude oil and refined products pipelines located throughout the United States and Canada.Canada as well as approximately 60 million barrels of active above-ground crude oil, refined products and LPG storage tanks, of which approximately 30 million barrels are utilized in our transportation segment. Our activities from pipelinetransportation operations generally consist of transporting volumes of crude oil and refined products for a fee and third-party leases of pipeline capacity (collectively referred to as "tariff activities"“tariff activities”), as well as barrel exchanges and buy/sell arrangements (collectively referred to as "pipeline“pipeline margin activities"activities”). In addition, we transport crude oil for third parties for a fee using our trucks and barges. These barge transportation services are provided through our 50% owned entity, Settoon Towing. Our transportation segment also includes our equity in earnings from our investment in Settoon Towing, Butte and Frontier. Butte and Frontier are pipeline systems in which we own approximately 22% and 22%, respectively. In connection with certain of our merchant activities conducted under our gathering and marketing business, we are also shippers on certaina number of 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.



      71

      The following table sets forth our operating results from our Pipeline Operationstransportation segment for the periods indicated:
                   
        Year Ended December 31, 
        2006  2005  2004 
        (In millions) 
       
                   
      Operating Results(1)
      		            
      Revenues            
      Tariff revenue $449.5  $381.1  $309.9 
      Pipeline margin activities  23.6   20.0   18.1 
      Third-party trucking  60.9   34.1   20.9 
                   
      Total pipeline operations revenues  534.0   435.2   348.9 
      Costs and Expenses            
      Pipeline margin activities purchases  (3.2)  (2.0)  (1.5)
      Third-party trucking  (68.1)  (48.2)  (26.4)
      Field operating costs (excluding LTIP charge)  (200.7)  (164.5)  (131.0)
      LTIP charge — operations(3)  (4.5)  (1.0)  (0.6)
      Segment G&A expenses (excluding LTIP charge)(2)  (42.9)  (40.2)  (36.6)
      LTIP charge — general and administrative(3)  (16.3)  (10.6)  (3.4)
      Equity in earnings from unconsolidated entities  1.9   0.8   0.5 
                   
      Segment profit $200.2  $169.5  $149.9 
                   
      Maintenance capital $20.0  $8.5  $7.7 
                   
      Segment profit per barrel $0.26  $0.26  $0.28 
                   
      Average Daily Volumes(thousands of barrels per day)(4)
      		            
      Tariff activities            
      All American  49   51   54 
      Basin  332   290   265 
      BOA/CAM  89   N/A   N/A 
      Capline  160   132   123 
      Cushing to Broome  73   66   N/A 
      North Dakota/Trenton  89   77   39 
      West Texas/New Mexico Area Systems(5)  433   428   338 
      Canada  272   255   263 
      Other  521   426   330 
                   
      Total tariff activities  2,018   1,725   1,412 
      Pipeline margin activities  88   74   74 
                   
      Transportation Activities Total
      		  2,106   1,799   1,486 
                   
      (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 management’s assessment of the business activities for that period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period.
      (3)Compensation expense related to our 1998 Long-Term Incentive Plan (“1998 LTIP”), our 2005 Long-Term Incentive Plan (“2005 LTIP”), and our 2006 Long-Term Incentive Tracking Unit Plan (“2006 Plan” and, together with the 1998 Plan and 2005 Plan, the “Long-Term Incentive Plans” or “LTIP”).


      72

       
      		 Year ended December 31,
      		 
       
      		 2003
      		 2002
      		 2001
      		 
      Operating Results(1) (in millions)          
       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  — 
        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)

      (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)The aggregate of multiple systems in the West Texas/New Mexico area.
      Segment profit, our primary measure of segment performance, was impacted by the number of daysfollowing:
      • Increased volumes and related tariff revenues — The increase in tariff revenues resulted from (i) higher volumes primarily from multi-year contracts on our Basin and Capline systems entered into during the third quarter of 2006 and the second quarter of 2006, respectively, (ii) increased volumes associated with the acquisition of the BOA/CAM/HIPS systems, (iii) higher volumes on various other systems, and (iv) increased revenues from loss allowance oil. As is common in the industry, our crude oil tariffs incorporate a “loss allowance factor” that is intended to offset losses due to evaporation, measurement and other losses in transit. The loss allowance factor averages approximately 0.2%, by volume. We value the variance of allowance volumes to actual losses at the average market value at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. Gains or losses on subsequent sales of allowance oil barrels are also included in tariff revenues. Increased volumes and higher crude oil prices during 2006 as compared to 2005 have resulted in increased revenues related to loss allowance oil. The average NYMEX crude oil price for 2006 was $66.27 per barrel versus $56.65 in 2005 and $41.29 in 2004. The increase in volumes and related tariff revenues in 2005 versus 2004 is primarily related to the Link acquisition and other acquisitions completed during 2005 and 2004. The increase primarily resulted from the inclusion of the related assets for the entire 2005 period versus only a portion of the 2004 period.
      • Increased field operating costs — Field operating costs have increased for most categories of costs for 2006 as we have continued to grow through acquisitions and expansion projects. The most significant cost increases in 2006 have been related to (i) payroll and benefits, (ii) utilities, (iii) integrity work, and (iv) property taxes. Utilities increased approximately $10 million in 2006 over the prior year due to a variety of factors including (i) an increase in electricity consumption related to increased volumes, partially offset by lower electricity market prices and (ii) atrue-up of prior and current accruals following receipt of final billing information upon expiration of an existing term arrangement with a significant electricity provider. Our costs increased in 2005 as compared to 2004, primarily from the Link acquisition and other acquisitions completed during 2004. The 2005 increased costs primarily relate to (i) payroll and benefits, (ii) emergency response and environmental remediation of pipeline releases, (iii) maintenance and (iv) utilities.
      • Increased segment G&A expenses — Segment G&A expenses excluding LTIP charges were relatively flat in 2006 compared to 2005. The increase in segment G&A expenses in 2005 is primarily related to the acquisition activity.
      • Increased LTIP expenses — LTIP charges included in field operating costs and segment G&A expenses increased approximately $9 million in 2006 over 2005, primarily as a result of an increase in our unit price to $51.20 at December 31, 2006 from $39.57 at December 31, 2005. LTIP-related charges increased approximately $8 million in 2005 over 2004, primarily as a result of LTIP grants made in 2005 and an increase in our unit price. Our unit price at December 31, 2004 was $37.74 per unit. See Note 10 to our Consolidated Financial Statements.



      (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.
      73

              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, wethe increase in transportation segment profit is largely related to our acquisition activities. We have completed a number of acquisitions during 20032006, 2005 and 20022004 that have impacted theour results of operations herein.operations. The



      following table reflects oursummarizes the year-over-year impact that recent acquisitions and expansion projects have had on tariff revenue and volumes:

                       
        Change in the Periods for the Year Ended December 31, 
        2006 vs 2005  2005 vs 2004 
        Revenues  Volumes  Revenues  Volumes 
        (Volumes in thousands of barrels per day and revenues in millions) 
       
      Tariff activities(1)(2)(3)
      		                
      2006 acquisitions/expansions $32.8   178  $N/A   N/A 
      2005 acquisitions/expansions  5.7   8   14.1   96 
      2004 acquisitions/expansions  2.7   28   22.6   140 
      2003 acquisitions/expansions  6.2   10   13.0   17 
      All other pipeline systems  21.0   69   21.5   60 
                       
      Total tariff activities
      		 $68.4   293  $71.2   313 
                       
      (1)Revenues include intersegment amounts.
      (2)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 year.
      (3)To the extent there has been an expansion to one of our existing pipeline systems, any incremental revenues and volumes from the expansion are included in the category for the period that the pipeline was acquired. For new pipeline systems that we construct, incremental revenues and volumes are included in the period the system became operational.
      In 2006, 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)(2)      
       2003 acquisitions 82 — —
       2002 acquisitions 344 171 —
       2001 acquisitions 200 193 134
       All other pipeline systems 198 200 211
        
      		 
      		 
       Total tariff activities average daily volumes 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.

      (2)
      We have decreased the number of barrels previously disclosed in the "Other domestic" line for the 2002 periodincreased by approximately 9,000.300 thousand barrels per day or 17% and tariff revenues increased by approximately $68 million or 18%. The adjustment reflects an eliminationincrease in volumes and tariff revenues is attributable to a combination 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.

              The increasefollowing factors:

      • Pipeline systems acquired or brought into service during 2006, which contributed approximately 178,000 barrels per day and $33 million of revenues during 2006;
      • Revenues from some of the Canadian pipeline systems increased approximately $9 million in 2006 primarily due to the appreciation of Canadian currency (the Canadian to US dollar exchange rate appreciated to an average of 1.13 to 1 for 2006 compared to an average of 1.21 to 1 in 2005);
      • An increase of approximately $7 million from our loss allowance oil primarily resulting from higher crude oil prices;
      • Volumes and revenues from pipeline systems in which we entered into new multi-year contracts with shippers, which contributed approximately 70,000 barrels per day and approximately $4 million of revenues during 2006; and
      • Increased volumes and revenues from the North Dakota/Trenton pipeline system resulting from our expansion activities on that system.
      In 2005, average daily volumes from our tariff activities to 824,000increased by approximately 300 thousand barrels per day in 2003 from 564,000 barrels per dayor 22% and 345,000 barrels per day in 2002 and 2001, respectively, resulted primarilyrevenues from our acquisitiontariff 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 Items 1 and 2. "Business and Properties—Acquisitions and Dispositions—Shutdown and Partial Sale of Rancho Pipeline System").

      2001 Acquisitions—In addition, volumes on pipeline systems acquired in 2001 increased by approximately 7,000 barrels per day$71 million or 23%. The increase 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 volumestotal revenues 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 shutdowncombination 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 decreasedfollowing factors:

      • Pipeline systems acquired or brought into service during 2005, which contributed approximately 96,000 barrels per day and $14.1 million of revenues during 2005. Approximately 66,000 barrels per day and $7.2 million of revenues are attributable to our recently constructed Cushing to Broome pipeline system.


      74

      • Volumes and revenues from pipeline systems acquired in 2004 increased in 2005 as compared to 2004, reflecting the following:
      — An increase of 118,000 barrels per day and $15.8 million of revenues from the pipelines acquired in the Link acquisition, reflecting the inclusion of these systems for the entire 2005 period as compared to only a portion of the 2004 period. The 2005 period also includes (i) increased revenues from our loss allowance oil resulting from higher crude oil prices and (ii) increased revenues from the North Dakota/Trenton pipeline system resulting from our expansion activities on that system. These increases were partially offset by the impact of a reduction in tariff rates that were voluntarily lowered to encourage third party shippers. Transportation segment profit was reduced by approximately $12.0 million because of these market rate adjustments. As a result of these lower tariffs on barrels shipped by us in connection with our gathering and marketing activities, segment profit from marketing was increased by a comparable amount,
      — An increase of 17,000 barrels per day and $4.4 million of revenues from the pipelines acquired in the Capline acquisition, reflecting the inclusion of these systems for the entire 2005 period as compared to only a portion of the 2004 period, and
      — An increase of 5,000 barrels per day and $2.4 million of revenues from other businesses acquired in 2004.
      • Volumes and revenues from pipeline systems acquired in 2003 increased in 2005 as compared to 2004, reflecting the following:
      — An increase of 5,000 barrels per day and $5.2 million of revenues from the Red River pipeline system acquisition, reflecting increased tariff rates on the system, partially related to the quality of crude oil shipped,
      — An increase of $3.0 million of revenues related to higher realized prices on our loss allowance oil, and
      — An increase of 12,000 barrels per day and $4.8 million of revenues in 2005 compared to 2004 from other businesses acquired in 2003, primarily related to higher volumes.
      • Revenues from all other pipeline systems also increased in 2005, along with a slight increase in volumes. The increase in revenues is related to several items including:
      — The appreciation of Canadian currency (the Canadian to U.S. dollar exchange rate appreciated to an average of 1.21 to 1 for 2005 compared to an average of 1.30 to 1 in 2004), and
      — Volume increases on certain of our systems, partially related to a shift of certain minor pipeline systems from our marketing segment.
      Maintenance Capital



      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.

        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

      For the years ended December 31, 20022006, 2005 and 2001,2004, maintenance capital expenditures for our transportation segment were approximately $20.0 million, $8.5 million and $7.7 million, respectively. The increase in revenues was primarily related2006 is due to our pipeline margin activities, which increased bycontinued growth through acquisitions and expansion projects.
      Facilities
      As of December 31, 2006, we owned approximately $122.860 million in 2003. This increase was related to higher averagebarrels of active above-ground crude oil, prices coupledrefined products and LPG storage tanks, of which approximately 30 million barrels are included in our facilities segment. The remaining tanks are utilized in our transportation segment. At year end 2006, the Partnership was in the process of constructing approximately 12.5 million barrels of additional above ground terminalling and storage facilities, which we expect to place in service during 2007 and 2008.
      Our facilities segment generally consists of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products and LPG, as well as LPG fractionation and isomerization


      75

      services. On a stand-alone basis, segment profit from facilities activities is dependent on the storage capacity leased, volume of throughput and the level of fees for such services.
      We generate fees through a combination ofmonth-to-month and multi-year leases and processing arrangements. Fees generated in this segment include (i) storage fees that are generated when we lease tank capacity and (ii) terminalling fees, or throughput fees, that are generated when we receive crude oil or refined products from one connecting pipeline and redeliver crude oil or refined products to another connecting carrier.
      Our facilities segment also includes our equity earnings from our investment in PAA/Vulcan. At December 31, 2006, PAA/Vulcan owned and operated approximately 25.7 billion cubic feet of underground storage capacity and was constructing an additional 24 billion cubic feet of underground storage capacity.
      Total revenues for our facilities segment have increased over the three-year period ended December 31, 2006. The revenue increase in each period is driven primarily by 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 revenues(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 predominantlyresulting from our acquisition activities discussed above. and, to a lesser extent, tankage construction projects completed in 2005 and 2006.

      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 revenuessets forth our operating results from our tariff activities resulted from the inclusion of assets acquired in 2002facilities segment for the entire yearperiods indicated:

                   
        December 31, 
        2006  2005  2004 
        (In millions, except per barrel amounts) 
       
      Operating Results
      		            
      Storage and Terminalling Revenues(1) $87.7  $41.9  $33.9 
      Field operating costs  (39.6)  (17.8)  (11.0)
      LTIP charge — operations(3)  (0.1)  —   — 
      Segment G&A expenses (excluding LTIP charge)(2)  (13.5)  (7.7)  (3.6)
      LTIP charge — general and administrative(3)  (5.7)  (2.2)  (1.1)
      Equity earnings in unconsolidated entities  5.8   1.0   — 
                   
      Segment profit $34.6  $15.2  $18.2 
                   
      Maintenance capital $4.9  $1.1  $2.0 
                   
      Segment profit per barrel $1.49  $0.87  $1.23 
                   
      Volumes(millions of barrels)(4)
      		            
      Crude oil, refined products and LPG storage (average monthly capacity in millions of barrels)  20.7   16.8   14.8 
                   
      Natural gas storage, net to our 50% interest (average monthly capacity in billions of cubic feet)  12.9   4.3   — 
      LPG processing (thousands of barrels per day)  12.2   —   — 
      Facilities activities total (average monthly capacity in millions of barrels)(5)
      		  23.2   17.5   14.8 
                   
      (1)Revenues 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 management’s assessment of the business activities for that period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period.
      (3)Compensation expense related to our Long-Term Incentive Plans.
      (4)Volumes associated with acquisitions represent total volumes for the number of months we actually owned the assets divided by the number of months in the period.
      (5)Calculated as the sum of: (i) crude oil, refined products and LPG storage capacity; (ii) natural gas storage capacity divided by 6 to account for the 6:1 mcf of gas to crude oil barrel ratio; and (iii) LPG processing


      76

      volumes multiplied by the number of days in the month and divided by 1,000 to convert to monthly volumes in millions.
      Segment profit (our primary measure of segment performance) and revenues were impacted in 20032006 by the following:
      • Increased revenues from crude facilities — The increase in volumes and related revenues during 2006 primarily relates to (i) increased volumes stored due to a pronounced contango market, (ii) the Pacific acquisition and other acquisitions completed during 2006 and 2005, and (iii) the utilization of capacity at the Mobile facility that was acquired from Link in 2004 but not used extensively until 2006;
      • Increased revenues from LPG facilities — The increase in volumes and related revenues during 2006 primarily relates to four LPG facilities that were brought into service during 2005 but were operational for the entire 2006 period compared to only a portion of 2005;
      • Increased revenues from refined product storage and terminalling — The Pacific acquisition introduced a refined products storage and terminalling revenue stream in 2006, which contributed additional revenues of $5.3 million; and
      • Increased revenues from LPG processing — The acquisition of the Shafter processing facility during 2006 resulted in additional processing revenues of approximately $24 million.
      Segment profit was also impacted in 2006 by the following:
      • Increased field operating costs — Our continued growth, primarily from the acquisitions completed during 2006 and 2005 and the additional tankage added in 2006 and 2005, is the principal cause of the increase in field operating costs in 2006. Of the total increase, $10.9 million relates to the operating costs associated with the Shafter processing facility. The remainder of the increase in operating costs primarily relate to (i) payroll and benefits, (ii) maintenance and (iii) utilities;
      • Increased segment G&A expenses — Segment G&A expenses excluding LTIP charges increased in 2006 compared to 2005 primarily as a result of an increase in the indirect costs allocated to the facilities segment in 2006 as the operations have grown in that period;
      • Increased LTIP expenses — LTIP charges included in field operating costs and segment G&A expenses increased approximately $3.6 million in 2006 over 2005, primarily as a result of an increase in our unit price to $51.20 at December 31, 2006 from $39.57 at December 31, 2005. LTIP related charges increased approximately $1.1 million in 2005 over 2004 primarily as a result of LTIP grants made in 2005 and an increase in our unit price. Our unit price at December 31, 2004 was $37.74 per unit (see Note 10 to our Consolidated Financial Statements); and
      • Increased equity in earnings from unconsolidated entities — Our investment in PAA/Vulcan contributed $4.8 million in additional earnings, reflecting the inclusion of this investment for the entire 2006 period compared to only two months in 2005.
      Segment profit and revenues also increased in 2005 compared to only a portion of 2002. This2004 and were impacted by the following:
      • Increased revenues from crude facilities — The increase in volumes and related revenues during 2005 primarily relates to (i) increased volumes stored due to a pronounced contango market, (ii) acquisitions completed during 2005 and 2004, and (iii) increased throughput at our Cushing terminal; and
      • Increased revenues from LPG facilities — The increase in volumes and related revenues during 2005 primarily relates to acquisitions of new facilities completed during 2005; at the end of 2005, we owned ten facilities compared to four at the beginning of 2004.
      Segment profit in 2005 was entirely related toalso impacted by the assets acquiredfollowing:
      • Increased field operating costs — Our continued growth, primarily from the acquisitions completed during 2005 and 2004 and the additional tankage added in 2005 and 2004, is the principal cause of the increase in


      77

      field operating costs in 2005. The increased costs primarily relate to (i) payroll and benefits, (ii) maintenance and (iii) utilities; and
      • Increased segment G&A expenses — Segment G&A expenses excluding LTIP charges increased in 2005 compared to 2004 primarily as a result of an increase in the indirect costs allocated to the facilities segment in 2005 as the operations grew in that period. LTIP related charges increased approximately $1.1 million in 2005 over 2004 primarily as a result of LTIP grants made in 2005 and an increase in our unit price. Our unit price at December 31, 2004 was $37.74 per unit.
      Maintenance Capital
      For 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 Items 1 and 2. "Business and Properties—Acquisitions and Dispositions—Shutdown and Partial 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 yearyears ended December 31, 2003, from an average rate of 1.57 to 12006, 2005 and 2004, maintenance capital expenditures for the year ended December 31, 2002. Revenues from these systems increased to $21.6our facilities segment were approximately $4.9 million, in 2002 from $9.9 million in 2001 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$1.1 million and $19.4$2.0 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. This amount is approximately equal to the threshold amounts we must incur before the sellers' indemnities take effect. 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 20032006 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, 2002additional maintenance requirements at our Alto and 2001, maintenance capital expenditures were approximately $6.4 million, $3.4 million and $0.5 million, respectively for our pipeline operations

      Shafter facilities.

      segment. The increases between the years are related to our continued growth, primarily through acquisitions.

      Gathering, Marketing Terminalling and Storage Operations

      Our revenues from gathering and marketing activities reflect the sale of gathered and bulk purchasedbulk-purchased crude oil and LPG volumes, as well as marketing of natural gas liquids, 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 ourprices. However, the margins related to those purchases and sales. For example, our revenues increased approximately 51% in 2003 compared to the prior year, while our segment profit increased 7% in the same period. Approximately 55% of the increase in revenues related to increased sales volumeswill not necessarily have corresponding increases and the remaining 45% of the increase resulted from higher average prices in 2003. The increase in sales volumes primarily related to barrels sold under buy/sell and bulk purchase arrangements, both of which generate significantly less margin than our lease gathered barrels.decreases. We do not consider barrels sold under these arrangements toanticipate that future changes in revenues will be a primary driver of segment performance and they are not included in the volumes we disclose as lease gathered barrels, which are a primary driver of segment performance. Segment profits from these arrangements are generally lower and not as sustainable as our lease purchased barrels, as they are driven mainly by market opportunity, and can vary significantly from month to month. With respect to a relationship between volumes and segment profit,profit. Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in our marketing segment volumes (which consist of (i) lease gathered volumes, and(ii) LPG sales, volumes.and (iii) waterborne foreign crude imported) as well as the overall volatility and strength or weakness of market condition and the allocation of our assets among our various hedge positions. In addition, the execution of our risk management strategies in conjunction with our assets can provide upside in certain markets. Although we believe that the combination of our lease gatheringgathered business and our storage assets providehedging activities provides a counter cyclicalcounter-cyclical balance whichthat provides stability in our margins, these margins are not fixed and may vary from yearperiod to year. period.
      Revenues from our marketing operations were approximately $22.1 billion, $30.9 billion and $20.8 billion for the years ended December 31, 2006, 2005 and 2004, respectively. Total revenues for our marketing segment decreased in 2006 as compared to 2005 due to a combination of the following factors:
      • A decrease in our 2006 revenues due to the adoption of EITF04-13 which was equally offset with purchases and related costs and does not impact segment profit (see Note 2 to our Consolidated Financial Statements); offset by
      • An increase in the average NYMEX price for crude oil in 2006 as compared to 2005. The average NYMEX price for crude oil was $66.27, $56.65 and $41.29 per barrel for the years ended December 31, 2006, 2005 and 2004, respectively. 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.


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      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 salesmarketing segment volumes and (iii) segment profit per barrel calculated on these volumes.

              We own and operate approximately 24.0 million barrels of above-ground crude oil terminalling and storage facilities, including a crude oil terminalling and storage facility at Cushing, Oklahoma. Cushing, which we refer to as the Cushing Interchange, is one of the largest crude oil market hubs in the United States and the designated delivery point for New York Mercantile Exchange, or NYMEX, crude oil futures contracts. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling." Approximately 11.0 million barrels of our 24.0 million barrels of tankage is used primarily in our Gathering, Marketing, Terminalling and Storage Operations and the balance is used in our Pipeline Operations segment. On a stand alone basis, segment profit from terminalling and storage activities is dependent on the throughput of volumes, the volume of crude oil stored and the level of fees generated from our terminalling and storage services. Our terminalling and storage activities are integrated with our gathering and marketing activities and the level of tankage that we allocate for our arbitrage activities (and therefore not available for lease to third parties) varies throughout crude oil price cycles. This integration enables us to use our storage tanks in an effort to counter-cyclically balance and hedge our gathering and marketing activities. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (when oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow. We believe that this combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flows.



              As a result of completing our Phase II and III expansions at our Cushing facility, total Cushing tankage dedicated to our Gathering, Marketing, Terminalling and Storage Operations was approximately 1.5 million barrels greater in 2003 relative to 2002. A portion of such tankage was employed in hedging activities related to our gathering and marketing activities in 2003 and the latter portion of 2002.

              During 2003, market conditions were extremely volatile as a confluence of several events caused the NYMEX benchmark price of crude oil to fluctuate widely with prices ranging from as high as $39.99 per barrel to as low as $25.04 per barrel. For much of the first eight months of 2003, the crude oil market was in steep backwardation. Although the crude oil market was characterized by high absolute prices in the fourth quarter, the average backwardation for the quarter was in line with a normal crude oil market. These market conditions and volatility, in conjunction with our hedging strategies, enhanced the returns of our gathering and marketing activities. This was partially offset by the negative impact that the August 2003 blackout had on our fourth quarter margins. In contrast, market conditions during 2002 were less favorable as the crude oil market alternated between periods of weak contango and strong backwardation. In 2001, the market alternated between weak contango and weak backwardation.

      The following table sets forth our operating results from our Gathering, Marketing, Terminalling and Storage Operationsmarketing segment for the comparable periods indicated:

       
      		 December 31,
      		 
       
      		 2003
      		 2002
      		 2001
      		 
      Operating Results(1) (in millions)          
       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 except as otherwise noted)(4)(5)          
      Crude oil lease gathering  437  410  348 
      Crude oil bulk purchases  90  68  46 
        
      		 
      		 
      		 
       Total  527  478  394 
        
      		 
      		 
      		 
      LPG sales  38  35  19 
        
      		 
      		 
      		 
      (1)
      Revenue and purchases include intersegment amounts.

      (2)
                   
        December 31, 
        2006  2005  2004 
        (In millions, except per barrel amounts) 
       
      Operating Results(1)
      		            
      Revenues(2)(3) $22,060.8  $30,893.0  $20,750.7 
      Purchases and related costs(4)(5)  (21,640.6)  (30,578.4)  (20,551.2)
      Field operating costs (excluding LTIP charge)  (136.6)  (94.4)  (80.9)
      LTIP charge — operations(6)  (0.1)  (2.3)  — 
      Segment G&A expenses (excluding LTIP charge)(7)  (39.5)  (32.5)  (35.2)
      LTIP charge — general and administrative(6)  (16.0)  (10.0)  (2.8)
                   
      Segment profit(3) $228.0  $175.4  $80.6 
                   
      SFAS 133mark-to-market adjustment(3)
      		 $(4.4) $(18.9) $1.0 
                   
      Maintenance capital $3.3  $4.4  $1.6 
                   
      Segment profit per barrel(8) $0.80  $0.66  $0.34 
                   
      Average Daily Volumes(thousands of barrels per day)(9)
      		            
      Crude oil lease gathering  650   610   589 
      LPG sales  70   56   48 
      Waterborne foreign crude imported  63   59   12 
                   
      Marketing Activities Total
      		  783   725   649 
                   
      (1)Revenues and purchases and related costs include intersegment amounts.
      (2)Includes revenues associated with buy/sell arrangements of $4,761.9 million, $16,274.9 million and $11,396.8 million for the years ended December 31, 2006, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 919,500, 851,900 and 800,700 barrels per day for the years ended December 31, 2006, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on management’s judgment; such estimates are not expected to have a material impact on the balances. See Note 2 to our Consolidated Financial Statements.
      (3)Amounts related to SFAS 133 are included in revenues and impact segment profit.
      (4)Includes purchases associated with buy/sell arrangements of $4,795.1 million, $16,106.5 million and $11,280.2 million for the years ended December 31, 2006, 2005 and 2004, respectively. Volumes associated with these arrangements were approximately 926,800, 851,900 and 800,700 barrels per day for the years ended December 31, 2006, 2005 and 2004, respectively. The previously referenced amounts include certain estimates based on management’s judgment; such estimates are not expected to have a material impact on the balances. See Note 2 to our Consolidated Financial Statements.
      (5)Purchases and related costs include interest expense on contango inventory purchases of $49.2 million, $23.7 million and $2.0 million for the years ended December 31, 2006, 2005 and 2004, respectively.
      (6)Compensation expense related to our Long-Term Incentive Plans.
      (7)Segment G&A expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments based on management’s assessment of the business activities for that period. The proportional allocations by segment require judgment by management and may be adjusted in the future based on the business activities that exist during each period.


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      (8)Calculated based on crude oil lease gathered volumes, LPG sales volumes, and waterborne foreign crude volumes.
      (9)Volumes associated with acquisitions represent total volumes for the number of days we actually owned the assets divided by the number of days in the period.
      Segment profit for 2006 ($228.0 million) exceeded the segment profit for 2005 ($175.4 million). The increase was primarily related to very favorable market conditions and successful execution of risk management strategies coupled with increased volumes and synergies realized from businesses acquired in the last two years.
      The primary factors affecting current period results were:
      • Acquisitions — During 2006 we purchased certain crude oil gathering assets and related contracts in South Louisiana and Andrews Petroleum and Lone Star Trucking. The Andrews acquisition impacted our facilities, marketing and transportation segments. See Note 3 to our Consolidated Financial Statements.
      • Favorable market conditions and execution of our risk management strategies — During 2006 and 2005, the crude oil market experienced significantly high volatility in prices and market structure. The NYMEX benchmark price of crude oil ranged from $54.86 to $78.40 during 2006. The volatile market allowed us to utilize risk management strategies to optimize and enhance the margins of our gathering and marketing activities. The market was in contango for most of 2006 and the time spread of prices averaged approximately $1.22 versus $0.72 for 2005; this increase in spreads was partially offset by an increase in the cost to carry the inventory that was not only impacted by the increase in LIBOR rates but also by the increase in NYMEX prices. Marketing segment profit includes contango and other hedged inventory related interest expense of approximately $49.2 million for 2006 incurred to store the crude oil. This cost is included in Purchases and related costs in the table above.
      • SFAS 133mark-to-market — 2006 includes SFAS 133mark-to-market losses of $4.4 million compared to a loss of $18.9 million for 2005. See Note 6 to our Consolidated Financial Statements.
      • Inventory Adjustment — In 2006, we recognized a $5.9 million non-cash charge primarily associated with declines in oil prices and other product prices during the third and fourth quarters of 2006 and the related decline in the valuation of working inventory volumes. Approximately $3.4 million of the charge relates to crude oil inventory in pipelines owned by third parties and the remainder relates to LPG and other products inventory.
      • Field operating costs and segment G&A expenses —  Field operating costs (excluding LTIP charges) increased in 2006 compared to 2005, primarily as a result of increases in (i)  payroll and benefits and contract transportation as a result of 2006 acquisitions, (ii) fuel costs and (iii) maintenance costs. The increase in general and administrative expenses (excluding LTIP charges) is primarily the result of an increase in the indirect costs allocated to the marketing segment in 2006 as the operations have grown. The increase in field operating costs in 2005 compared to 2004 was primarily the result of an increase in (i) fuel costs and (ii) payroll and benefits.
      • Increased LTIP expenses — LTIP charges included in field operating costs and segment G&A expenses increased approximately $3.8 million in 2006 over 2005, primarily as a result of an increase in our unit price to $51.20 at December 31, 2006 from $39.57 at December 31, 2005. LTIP related charges increased approximately $9.5 million in 2005 over 2004 primarily as a result of LTIP grants made in 2005 and an increase in our unit price. Our unit price at December 31, 2004 was $37.74 per unit. See Note 10 to our Consolidated Financial Statements.
      Segment profit per barrel (calculated 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 areour marketing volumes included in revenues and impact segment profit.

      (4)
      Volumes associated with acquisitions represent total volumes transportedthe table above) was $0.80 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 as2006, compared to 2002:$0.66 for 2005 and $0.34 for 2004. As discussed above, our current period results were impacted by favorable market conditions. We are not able to predict with any reasonable level of accuracy whether market conditions will remain as favorable as have recently been experienced, and these operating results may not be indicative of sustainable performance.


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      Maintenance capital
      For the overall counter-cyclical balance ofyears ended December 31, 2006, 2005 and 2004, maintenance capital expenditures were approximately $3.3 million, $4.4 million, and $1.6 million, respectively, for our assetsmarketing segment.
      Other Income and the flexibility embedded in our business strategy;

      •
      increased tankage available to our gatheringExpenses
      Depreciation and marketing business;

      •
      increased lease gathering volumes;

      •
      the backwardated market structureAmortization
      Depreciation and volatile market conditions;

      •
      increased sales and higher margins in our LPG activities for the first quarter because of cold weather throughout the U.S. and Canada; and

      •
      appreciation of Canadian currency (the Canadian dollar to U.S. dollar exchange rate appreciated to an average of 1.40 to 1amortization expense was $100.4 million for the year ended December 31, 2003, from an average of 1.57 to 1 for the year ended December 31, 2002).

              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 as2006, 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$83.5 million and $73.7$68.7 million for the years ended December 31, 20022005 and 2001,2004, respectively. The increaseincreases in 2003 includes $4.3 million2006 and 2005 related primarily to the probable vestingan increased amount 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—Unallocated G&A Expense." 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&Adepreciable assets 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 dueactivities and capital projects. Also contributing to the inclusion of those assets for all of 2002 compared to onlyincrease in 2005 was a portion of 2001. This increase was offset by decreased segment G&A of $2.6 million from our domestic operations. This decrease was partiallynon-cash loss related to a reductionsales of assets. Amortization of debt issue costs was $2.5 million in accounting2006, $2.8 million in 2005, and consulting costs$2.5 million in 2002 from those that had been incurred in 2001. Partially offsetting these items is the approximately $2.42004.

      Interest Expense
      Interest expense was $85.6 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, 2003,2006, 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.

        Maintenance capital

              For the periods ended December 31, 2003, 2002 and 2001, maintenance capital expenditures were approximately $1.2 million, $2.6$59.4 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.


      Other Income and Expenses

        Unallocated G&A Expenses

              Total G&A expenses were $73.0 million, $45.7 million and $46.6$46.7 million for the years ended December 31, 2003, 20022005 and 2001,2004, respectively. We have includedInterest expense is primarily impacted by:

      • our average debt balances;
      • the level and maturity of fixed rate debt and interest rates associated therewith;
      • market interest rates and our interest rate hedging activities on floating rate debt; and
      • interest capitalized on capital projects.
      The following table summarizes selected components of our average debt balances:
                               
        For the Year Ended December 31, 
        2006  2005  2004 
        Total  % of Total  Total  % of Total  Total  % of Total 
        (Dollars in millions) 
       
      Fixed rate senior notes(1) $1,336   92% $891   87% $586   68%
      Borrowings under our revolving credit facilities(2)  118   8%  135   13%  274   32%
                               
      Total $1,454      $1,026      $860     
                               
      (1)Weighted average face amount of senior notes, exclusive of discounts.
      (2)Excludes borrowings under our senior secured hedged inventory facility and capital leases.
      The issuance of senior notes and the assumption of Pacific’s debt in 2006 resulted in an increase in the above segment discussion the G&A expenses for eachaverage amount of these years thatlonger term and higher cost fixed-rate debt outstanding in 2006. The overall higher average debt balances in 2006 and 2005 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 nearlyprimarily related to the execution stage when it was abruptly terminated by the seller. As a result,portion of 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 millionacquisitions that were not financed with equity, coupled with borrowings related to other capital projects. During 2006, 2005 and 2004, the average LIBOR rate was 5.0%, 3.2%, and 1.6%, respectively. Our weighted average interest rate, excluding commitment and other fees, was approximately 6.1% in 2006, compared to 5.6% and 5.0% in 2005 and 2004, respectively. The impact of the increased debt balance was an increase in interest expense of $26.0 million, and the impact of the higher weighted-average interest rate was an increase in interest expense of $4.7 million. Both of these increases were primarily offset by an increase in capitalized interest of $4.2 million. The net impact of the items discussed above was an increase in interest expense in 2006 of approximately $26.2 million.

      The higher average debt balance in 2005 as compared to 2004 resulted in additional interest expense of approximately $12.7 million, while at the same time our commitment and other fees decreased by approximately $1.8 million. Our weighted average interest rate, excluding commitment and other fees, was approximately 5.6% for 2005 compared to 5.0% for 2004. The higher weighted average rate increased interest expense by approximately $12.7 million in 2005 compared to 2004.


      81

      Interest costs 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 ownershipborrowings for inventory stored in a portion ofcontango market are included in purchases and related costs in our common units owned by it.marketing segment profit as we consider interest on these borrowings a direct cost to storing the inventory. 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 directorsborrowings are primarily under our LTIP, vested. This resulted in a charge to our 2001 income ofsenior secured hedged inventory facility. These costs were approximately $6.1$49.2 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$23.7 million and $24.3$2.0 million for the years ended December 31, 20022006, 2005 and 2001,2004, respectively. The increase in 2003 relates primarily to the inclusion

      Outlook
      This section identifies certain matters of the assets from the Shell acquisition for the entire year as compared to a portionrisk and uncertainty that may affect our financial performance and results 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 both of the years ended December 31, 2002 and 2001, respectively. The increase in 2003 compared to 2002 was primarily related to an increaseoperations 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, 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

      future.

      entered into hedging arrangements to lock in interest rates on approximately $50 million of its 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 (See "—Liquidity and Capital Resources—Credit Facilities and Long-term Debt"). 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

              Crude Oil and LPG Inventory.    We value our crude oil and LPG inventory at the lower of cost or market, with cost determined using an average cost method. At December 31, 2003 we had approximately 3.7 million barrels of inventory classified as unhedged operating inventory at a weighted average cost of $25.41 per barrel. The lower of cost or market method requires a write down of inventory to the market price at the end of a period in which our weighted average cost exceeds the market price. This method does not allow a write up of the inventory if the market price subsequently increases. We did not have an adjustment in this period. However, future fluctuations in crude oil prices could result in a period end lower of cost or market adjustment.

      Ongoing Acquisition Activities.  Consistent with our business strategy, we are continuously engaged in discussions withregarding potential sellers regarding the possible purchaseacquisitions by us of transportation, gathering, terminalling or storage assets and related midstream crude oil assets. 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.businesses. These acquisition efforts often involve assets which,that, if acquired, wouldcould 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 midstream businesses outside of the scope of our current operations, but with respect to which these resources effectively can be applied. For example, during 2006 we entered the refined products transportation and storage business as well as the barge transportation business. We are currently involvedpresently engaged in advanced discussions and negotiations with a potential sellervarious parties regarding the purchase by usacquisition of crude oil pipeline, terminalling, storageassets and gathering and marketing assets for an aggregate purchase price, including assumed liabilities and obligations, ranging from $300 million to $400 million. Such transaction is subject to confirmatory due diligence, negotiation of a mutually acceptable definitive purchase and sale agreement, regulatory approval and approval of both our board of directors and that of the seller.

              In connection with our acquisition activities,businesses described above, but 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 $0.4 million in deferred costs at December 31, 2003. We estimate that our deferred acquisition costs will increase in the first quarter of 2004 by approximately $0.7 million. 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.

      Pipeline Integrity and Storage Tank Testing Compliance.  Although we believe our short-term estimates of costs under the pipeline integrity management rules and API 653 (and similar regulations in Canada) are reasonable, a high degree of uncertainty exists with respect to estimating such costs, as we continue to test existing assets and as we acquire additional assets.
      In September 2006, the DOT published a Notice of Proposed Rulemaking (“NPRM”) that proposed to regulate certain hazardous liquid gathering and low stress pipeline systems that are not currently subject to regulation. On December 16, 2003, we entered6, 2006, the Congress passed, and on December 29, 2006 President Bush signed into law, H.R. 5782, the “Pipeline Inspection, Protection, Enforcement and Safety Act of 2006” (2006 Pipeline Safety Act), which reauthorizes and amends the DOT’s pipeline safety programs. Included in the 2006 Pipeline Safety Act is a definitive agreement to acquire all of Shell Pipeline Company LP's ("SPLC") interests in two entities. The principal assetsprovision eliminating the regulatory exemption for hazardous liquid pipelines operated at low stress, which was one of the entities are: (i) an approximate 22% undivided joint interest infocal points of the Capline Pipe Line System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System.September 2006 NPRM. The Capline Pipeline System is a 667-mile, 40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a 57-mile, 20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois.

              During 2003, average daily volumes on SPLC's interest in the Capline system were 125,000 barrels, a decrease from an average of 166,000 barrels per day in 2002 and 213,000 barrels per day in 2001. EffectiveAct requires DOT to issue regulations by December 1, 2003, SPLC modified its tariff structure in an effort to increase volume shipments on its space. On a month-to-month basis, average daily volumes on this system are31, 2007 for those hazardous liquid low stress pipelines now subject to significant volatility. Our acquisition analysis assumed thatregulation pursuant to the average daily volumes on theAct. Regulations issued by December 31, 2007 with respect to hazardous liquid low stress pipelines would be between 110,000 and 125,000 barrels per day, although it is possible that the volumes will decline below those levels.

              The total purchase priceas well as any future regulation of hazardous liquid gathering lines could include requirements for the transactionestablishment of additional pipeline integrity management programs for these newly regulated pipelines. We do not currently know what, if any, impact these developments will have on our operating expenses and, thus, cannot provide any assurances that future costs related to these programs will not be material.

      In addition to performing DOT-mandated pipeline integrity evaluations, during 2006, we expanded an internal review process started in 2005 in which we are reviewing various aspects of our pipeline and gathering systems that are not subject to the DOT pipeline integrity management rule. The purpose of this process is approximately $158 million (approximately $142 million, netto review the surrounding environment, condition and operating history of these pipelines and gathering assets to determine if such assets warrant additional investment or replacement. Accordingly, we may be required (as a result of additional DOT regulation) or we may elect (as a result of our own initiatives) 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 deposit paid).pipelines. We have sufficient immediate availability under our revolving credit facilities to consummate this transaction. Consistent with our financial growth strategy of funding our acquisition growth with a balance of equity and debt, in December 2003, we issued approximately 2.8 million common units in anticipation of the consummation of this acquisition. See "—Liquidity and Capital Resources—Liquidity."

              This acquisition is expected to close during the first quarter of 2004. While we believe it is reasonable to expect the acquisition to close in the first quarter of 2004, we cancannot provide noany assurance as to whenthe ultimate amount or whether the acquisition will close.timing of future pipeline integrity expenditures for environmental compliance.


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              Basin Expansion.    In February 2004, we announced plans to expand a 345-mile section of the system. The section to be expanded extends from Colorado City, Texas to our Cushing Terminal. Upon the completion of this estimated $1.1 million expansion, the capacity of this section will increase approximately 15%, from 350,000 barrels per day to approximately 400,000 barrels per day.

              OCS Production.    In October 2003 Plains Exploration and Production announced that they had received all of the necessary permits to develop a portion of the Rocky Point structure that is accessible from the Point Arguello platforms and it appears that they will commence drilling activities in the second quarter of 2004. Such drilling activities, if successful, 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 assurances that our volumes transported would increase as a result of this drilling activity.

              Conversion of Subordinated Units and LTIP vesting.    In November of 2003, 25% of our outstanding subordinated units converted on a one-for-one basis into common units. During February 2004, the remaining subordinated units converted. As a result, distribution rights are now pari passu among all limited partner units. Further, as a result of these conversions, approximately 326,000 phantom units granted under our LTIP vested in February 2004, and we anticipate that another approximately 473,000 phantom units will vest in May 2004, subject to the satisfaction of service period requirements. We have



      accrued the majority of the estimated expense associated with the vesting of these units, however, we expect to incur an additional $1.9 million in the first quarter of 2004 and $0.6 million in the second quarter of 2004 primarily related to amortization of service period requirements. We expect to satisfy the May vesting of phantom units by paying cash for the settlement of approximately 201,000 phantom units in lieu of delivering common units and issuing approximately 181,000 common units (after netting for taxes) to satisfy the remainder of the vesting. See Item 11. "Executive Compensation—Long-Term Incentive Plan."

              FERC Quarterly Reporting.    On February 11, 2004 the FERC issued the final rules on quarterly reporting with, among other things, the addition of the FERC Form No. 6-Q Quarterly Financial Reporting of Oil Pipeline Companies. Our first filing will be due on July 23, 2004. The rules as finalized differ from the original proposal, and we are still analyzing the potential costs associated with compliance. It does not appear at this point that such costs will have a material effect on our financial condition or results of operations, but will add incrementally to our overall regulatory compliance costs.

              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 the Partnership. These costs will have an adverse impact on future income and cash flow.

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

        1.
        Continued overall depletion of U.S.relating to crude oil production.

        2.
        The continuing convergence of worldwide crude oil supply and demand lines.

        3.
        Aggressive practices in the U.S. to maintain working crude oil inventory levels below historical levels.

        4.
        Industry compliance with the Department of Transportation's adoption of the American Petroleum Institute's standard 653 for testing and maintenance of storage tanks, which will require significant investments to maintain existing crude oil inventory capacity or, alternatively, will result in a reduction of existing inventory capacity by 2009.

        5.
        The introduction of increased crude oil production from North American supplies (primarily Canadian oil sands and deepwater Gulf of Mexico sources) that will, of economic necessity, compete for U.S markets currently being supplied by non-North American foreign crude imports.

      include:

      • Continued overall depletion of U.S. crude oil production.
      • The continuing convergence of worldwide crude oil supply and demand trends.
      • The expected extension of DOT regulations to low stress and gathering pipelines.
      • Industry compliance with the DOT’s adoption of API 653 for testing and maintenance of storage tanks, which will require significant investments to maintain existing crude oil storage capacity or, alternatively, will result in a reduction of existing storage capacity by 2009.
      • The addition of inspection requirements by EPA for storage tanks not subject to DOT’s API 653 requirements.
      • The expectation of increased crude oil production from certain North American regions (primarily Canadian oil sands and deepwater Gulf of Mexico sources) that will, of economic necessity, compete for U.S. markets currently being supplied by non-North American foreign crude imports.
      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.swings, which were evident in 2005. 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.


      We are also regularly evaluating midstream businesses that are complementary to our existing businesses and that possess attractive long-term growth prospects. Through PAA/Vulcan’s acquisition of ECI in 2005, the Partnership entered the natural gas storage business. Although our investment in natural gas storage assets is currently relatively small when considering the Partnership’s overall size, we intend to grow this portion of our business through future acquisitions and expansion projects. We believe that strategically located natural gas storage facilities will become increasingly important in supporting the reliability of gas service needs in the United States. Rising demand for natural gas is outpacing domestic natural gas production, creating an increased need for imported natural gas. A continuation of this trend will result in increased natural gas imports from Canada and the Gulf of Mexico, and LNG imports. We believe our business strategy and expertise in hydrocarbon storage will allow us to grow our natural gas storage platform and benefit from these trends.
      During 2006, we entered the refined products transportation and storage business. We believe that this business will be driven by increased demand for refined products, growth in the capacity of refineries and increased reliance on imports. We believe that demand for refined products will increase as a result of multiple specifications of existing products (also referred to as boutique gasoline blends), specification changes to existing products, such as ultra low sulfur diesel, and new products, such as bio-fuels. In addition, “capacity creep” as well as large expansion projects at existing refineries will likely necessitate construction of additional refined products transportation and storage infrastructure. We intend to grow our asset base in the refined products business through future acquisitions and expansion projects. We also intend to apply our business model to the refined products business by establishing and growing a marketing and distribution business to complement our strategically located assets.
      Liquidity and Capital Resources
      The Partnership has a defined financial growth strategy that states how we intend to finance our growth and sets forth targeted credit metrics. We have also established a targeted credit rating. See Items 1 and 2. “Business and Properties — Financial Strategy.”


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        Liquidity

        Cash generatedflow from operations and our credit facilities are our primary sources of liquidity. At December 31, 2003,2006, we had a working capital deficit of approximately $68.9$133 million, and approximately $596.8 million$1.25 billion of availability under our committed revolving credit facilities and approximately $100$0.4 million of availability under theour uncommitted hedged inventory facility. Usage of the credit facilities is subject to ongoing compliance with covenants. We completed several transactionsbelieve we are currently in compliance with all covenants.
        Cash flow from operations
        The crude oil market was in contango for much of 2006 and 2005. Because we own crude oil storage capacity, during a contango market we can buy crude oil in the fourth quartercurrent month and simultaneously hedge the crude by selling it forward for delivery in a subsequent month. This activity can cause significant fluctuations in our cash flow from operating activities as described below.
        The primary drivers of 2003cash flow from our operations are (i) the collection of amounts related to the sale of crude oil and other products, the transportation of crude oil and other products for a fee, and storage and terminalling services, and (ii) the payment of amounts related to the purchase of crude oil and other products and other expenses, principally field operating costs and general and administrative expenses. 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 (i) in the months that increasedwe store the purchased crude oil and hedge it by selling it forward for delivery in a subsequent month because of contango market conditions or (ii) in months in which we increase our borrowing capacityshare of linefill in third party pipelines. The storage of crude oil in periods of a contango market can have a material negative impact on our cash flows from operating activities for the period in which we pay for and enhanced our liquidity position asstore the crude oil (as is the case for much of 2006, including at December 31, 2003.2006) and a material positive impact in the subsequent period in which we receive proceeds from the sale of the crude oil. In November 2003,the month we refinancedpay for the stored crude oil, we borrow under our senior secured credit facilities with new senior unsecured credit facilities totaling $750 million(or pay from cash on hand) to pay for the crude oil, which negatively impacts our operating cash flow. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil. Similarly, but to a lesser extent, the level of LPG and a $200 million uncommitted, senior secured facilityother product inventory stored and held for resale at period end affects our cash flow from operating activities.
        In periods when the market is not in contango, we typically sell our crude oil during the same month in which we purchase it. Our accounts payable and accounts receivable generally vary proportionately because we make payments and receive payments for the purchase and sale of crude oil in the same month, which is the month following such activity. However, when the market is in contango, our accounts receivable, accounts payable, inventory and short-term debt balances are all impacted, depending on the point of the cycle at any particular period end. As a result, we can have significant fluctuations in those working capital accounts, as we buy, store and sell crude oil.
        Our cash flow used in operating activities in 2006 was $275.3 million compared to cash provided by operating activities of $24.1 million in 2005. This change reflects cash generated by our recurring operations offset by an increase in certain working capital items of approximately $703 million. In 2006, the market was in contango and we increased our storage of crude oil and other products (financed through borrowings under our credit facilities), resulting in a negative impact on our cash flows from operating activities for the period, as explained above. The fluctuations in accounts receivable and other and accounts payable and other current liabilities are primarily related to purchases and sales of crude oil that generally vary proportionately.
        Cash flow from operating activities was $24.1 million in 2005 and reflects cash generated by our recurring operations (as indicated above in describing the primary drivers of cash generated from operations), offset by changes in components of working capital, including an increase in inventory. A significant portion of the increased inventory has been purchased and stored due to contango market conditions and was paid for during the period via borrowings under our credit facilities or from cash on hand. As mentioned above, this activity has a negative impact in the period that we pay for and store the inventory. In addition, there was a change in working capital resulting from higher NYMEX margin deposits paid during 2005 that had a negative impact on our cash flows from operations. The fluctuations in accounts receivable and other and accounts payable and other current liabilities are primarily related to purchases and sales of crude oil that generally vary proportionately.


        84

        Cash flow from operating activities was $104.0 million in 2004 and reflects cash generated by our recurring operations that was offset negatively by several factors totaling approximately $100 million. The primary factor was a net increase in hedged crude oil. oil and LPG inventory and linefill in third party assets that was financed with borrowings under our credit facilities (approximately $75 million net). Cash flow from operations was also negatively impacted by a decrease of approximately $20 million in prepayments received from counterparties to mitigate credit risk.
        Cash provided by equity and debt financing activities
        We alsoperiodically access the capital markets for both equity and debt financing. We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue from time to time up to an aggregate of $2 billion of debt or equity securities. At December 31, 2006, we have approximately $1.1 billion of unissued securities remaining available under this registration statement.
        Cash provided by financing activities was $1,927.0 million, $270.6 million and $554.5 million for each of the last three years, respectively. Our financing activities primarily relate to funding (i) acquisitions, (ii) internal capital projects and (iii) short-term working capital and hedged inventory borrowings related to our contango market activities. Our financing activities have primarily consisted of equity offerings, senior notes offerings and borrowings under our credit facilities. During 2006, we borrowed under our credit facilities to pay for the storage of crude oil and other products under contango market conditions.
        Equity Offerings.  During the last three years we completed several equity offerings as summarized in the table below. Certain of these offerings involved related parties. See Note 9 to our Consolidated Financial Statements:
                             
        2006  2005  2004 
          Net
        		     Net
        		     Net
        		 
        Units Proceeds(1)(2)  Units  Proceeds(1)  Units  Proceeds(1) 
         
        6,163,960 $305.6   5,854,000  $241.9   4,968,000  $160.9 
        3,720,930  163.2   575,000   22.3   3,245,700   101.2 
                             
        3,504,672  152.4      $264.2      $262.1 
                             
          $621.2                 
        (1)Includes our general partner’s proportionate capital contribution and is net of costs associated with the offering.
        (2)Excludes the common units issued and our general partner’s proportionate capital contribution of $21.6 million pertaining to the equity exchange for the Pacific acquisition.
        Senior Notes and Credit Facilities.  During the three years ended December 31, 2006 we completed the sale of $250 millionsenior unsecured notes as summarized in the table below.
                   
            Face
        		  Net
        		 
        Year
        		 
        Description
        		 Value  Proceeds(1) 
         
        2006 6.125% Senior Notes issued at 99.56% of face value $400  $398.2 
          6.65% Senior Notes issued at 99.17% of face value $600  $595.0 
          6.7% Senior Notes issued at 99.82% of face value $250  $249.6 
                   
        2005 5.25% Senior Notes issued at 99.5% of face value $150  $149.3 
                   
        2004 4.75% Senior Notes issued at 99.6% of face value $175  $174.2 
          5.88% Senior Notes issued at 99.3% of face value $175  $173.9 
        (1)Face value of notes less the applicable discount (before deducting for initial purchaser discounts, commissions and offering expenses).


        85

        During the year ended December 31, 2006, we had net working capital and hedged inventory borrowings of 5.625% senior notes in Decemberapproximately $618.8 million. These borrowings are used primarily for purchases of 2003, the proceeds of which were used to pay down outstanding balancescrude oil inventory that was stored. See “— Cash flow from operations.” During 2006 and 2005, we also had net repayments on our long-term revolving credit facilities. See "—facility of approximately $298.5 million and $143.7 million, respectively, resulting from cash generated from our operations and other financing activities. During 2004, we had net borrowings on our long-term revolving credit facility of approximately $64.9 million. During 2005, we had net working capital and hedged inventory borrowings of approximately $206.1 million and during 2004 we had net borrowings of approximately $42.8 million. For further discussion related to our credit facilities and long-term debt, see “— Credit Facilities and Long-TermLong-term Debt." In addition,”
        Capital Expenditures and Distributions Paid to Unitholders and General Partner
        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 and the financing activities discussed above. Our primary uses of cash are for our acquisition activities, capital expenditures for internal growth projects and distributions paid to our unitholders and general partner. See “— Acquisitions and Internal Growth Projects.” The price of the acquisitions includes cash paid, transaction costs and assumed liabilities and net working capital items. Because of the non-cash items included in anticipationthe total price of a potential pendingthe acquisition during December 2003, we completed a public offeringand the timing of 2,840,800 common units priced at $31.94 per unit. Net proceedscertain cash payments, the net cash paid may differ significantly from the offering, includingtotal price of the acquisitions completed during the year.
        Distributions to unitholders and general partner.  We distribute 100% of our available cash within 45 days after the end of each quarter to unitholders of record and to our general partner's proportionate capital contributionpartner. Available cash is generally defined as all of our cash and expenses associatedcash equivalents on hand at the end of each quarter less reserves established in the discretion of our general partner for future requirements. Total cash distributions made during the last three years were as follows (in millions, except per unit amounts):
                                  
          Distributions Paid    
          Common
        		  Subordinated
        		  GP      Distribution
        		 
        Year
        		 Units  Units(1)  Incentive  2%   Total  per Unit 
        2006 $224.9  $—  $33.1  $4.6   $262.6  $2.87 
        2005 $178.4  $—  $15.0  $3.6   $197.0  $2.58 
        2004 $142.9  $4.2  $8.3  $3.0   $158.4  $2.30 
                                  
        (1)The subordinated units were converted to common units in 2004.


        86

        2007 Capital Expansion Projects.  Our 2007 projects include the following projects with the offering, were approximately $88.4 million and were used to pay down outstanding balances on our revolving credit facilities.

        estimated cost for the entire year (in millions):

             
        Projects
        		 2007 
         
        St. James, Louisiana Storage Facility $75.0 
        Salt Lake City Expansion  55.0 
        Patoka Tankage  40.0 
        Cheyenne Pipeline  34.0 
        Martinez Terminal  27.0 
        Cushing Tankage — Phase VI  27.0 
        Paulsboro Expansion  20.0 
        West Hynes Tanks  15.0 
        Kerrobert Tankage  14.0 
        Fort Laramie Tank Expansion  12.0 
        High Prairie Rail Terminal  11.0 
        Pier 400  10.0 
        Other Projects  160.0 
             
        Subtotal  500.0 
        Maintenance Capital  45.0 
             
        Total $545.0 
             
        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.

        Cash Flows

                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 $68.5 $173.9 $(30.0)
         Investing activities  (225.3) (363.8) (249.5)
         Financing activities  157.2  189.5  279.5 

                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 and general and administrative expenses. 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 or in months that we increase linefill. 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 store the crude oil, we borrow on our credit facilities to pay for the crude oil so 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.

                Our positive cash flow from operations for 2003 resulted from cash generated by our recurring operations. A portion of these funds were used for crude oil linefill purchases of approximately



        $47 million, primarily attributable to increased linefill requirements related to 2003 and 2002 acquisitions. 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.

                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 (i) the payment of approximately $74 million for crude oil purchased and stored during 2002 but for which receipt of the proceeds occurred during 2003 and (ii) crude oil linefill purchases of approximately $11 million. 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. In addition, we purchased approximately $13.7 million of crude oil linefill attributable to increased linefill requirements.


                Investing Activities.    Net cash used in investing activities in 2003, 2002 and 2001 consisted predominantly of cash paid for acquisitions. Net cash used in 2003 was $225.3 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 potential pending 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. Net cash used in 2002 was $363.8 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. Net cash used in 2001 was $249.5 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.

                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.

          Universal Shelf

                We have filed with the Securities and Exchange Commission a universal shelf registration statement that, subject to effectiveness at the time of use, allows us to issue from time to time up to an aggregate of $700 million of debt or equity securities. At December 31, 2003, we have approximately $165 million of remaining availability under this registration statement.

          Credit Facilities and Long-term Debt

                During December 2003,

        In July 2006, we completedamended our senior unsecured revolving credit facility to increase the saleaggregate capacity from $1.0 billion to $1.6 billion and thesub-facility for Canadian borrowings from $400 million to $600 million. The amended facility can be expanded to $2.0 billion, subject to additional lender commitments, and has a final maturity of July 2011.
        In November 2006, we amended our senior secured hedged inventory facility to increase the capacity under the facility from $800 million to $1.0 billion. We also extended the maturity of the senior secured hedged inventory facility to November 2007.
        We also have several issues of senior debt outstanding that total $2.6 billion, excluding premium or discount, and range in size from $150 million to $600 million and mature at various dates through 2037. See Note 9 to our Consolidated Financial Statements.


        87

        In November 2006, in conjunction with the Pacific merger, we assumed two issues of Senior Notes with an aggregate principal balance of $425 million. Interest payments on the $175 million of 6.25% Senior Notes are due on March 15 and September 15 of each year. The notes mature on September 15, 2015. Interest payments on the $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 payments7.125% Senior Notes are due on June 15 and December 15 of each year. The notes mature on June 15, 2014. We have the option to redeem the notes, in whole or in part, at any time on or after the date noted at the following redemption prices:
                   
        $175 Million 6.25% Notes $250 Million 7.125% Notes
        Year Percentage Year Percentage
         
        September 2010 103.125% June 2009 103.563%
        September 2011 102.083 June 2010 102.375
        September 2012 101.042 June 2011 101.188
        September 2013 and   June 2012 and  
        thereafter 100.000 thereafter 100.000
        In October 2006, we issued $400 million of 6.125% Senior Notes due 2017 and $600 million of 6.65% Senior Notes due 2037. The notes were sold at 99.56% and 99.17% of face value, respectively. Interest payments are due on January 15 and July 15 of each year. We used the proceeds to fund the cash portion of our merger with Pacific. Net proceeds in excess of the cash portion of the merger consideration were used to repay amounts outstanding under our credit facilities and for general partnership purposes. In anticipation of the issuance of these notes, we had entered into $200 million notional principal amount of U.S. treasury locks to hedge the treasury rate portion of the interest rate on a portion of the notes. The treasury locks were entered into at an interest rate of 4.97%.
        During May 2006, we completed the sale of $250 million aggregate principal amount of 6.70% Senior Notes due 2036. The notes were sold at 99.82% of face value. Interest payments are due on May 15 and November 15 of each year. We used the proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.
        All our notes are fully and unconditionally guaranteed, jointly and severally, by all of our existing 100% owned subsidiaries, except for two subsidiaries that are minor.

                During November 2003, we refinanced our bank credit facilities with new senior unsecured credit facilities totaling $750 million and a $200 million uncommitted facility for the purpose of financing hedged crude oil. The $750 million of new facilities consist of:

          •
          a four-year, $425 million U.S. revolving credit facility;

          •
          a 364-day, $170 million Canadian revolving credit facility with a five-year term-out option;

          •
          a four-year, $30 million Canadian working capital revolving credit facility; and

            •
            a 364-day, $125 million revolving credit facility.

                  All of the facilities with the exception of the $200 million hedged inventory facility are unsecured. The $200 million hedged inventory 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 securedassets regulated by the inventory purchased under the facilityCalifornia Public Utility Commission, and certain minor subsidiaries. See Note 12 to our Consolidated Financial Statements.

          Our credit agreements and the associated accounts receivable, and will be repaid with the proceeds from the sale of such inventory. At December 31, 2003, we have approximately $100 million outstanding underindentures governing our hedged crude oil inventory facility resulting in unused uncommitted capacity of approximately $100 million under this facility.

                  Our credit facilities, the indenture governing the 5.625% senior notes and the indenture governing the 7.75% senior notes contain cross default provisions. Our credit facilitiesagreements 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:

            •
            incur indebtedness if certain financial ratios are not maintained;

            •
            grant liens;

            •
            engage in transactions with affiliates;

            •
            enter into sale-leaseback transactions;

            •
            sell substantially all of our assets or enter into a merger or consolidation.

          • incur indebtedness if certain financial ratios are not maintained;
          • grant liens;
          • engage in transactions with affiliates;
          • enter into sale-leaseback transactions; and
          • sell substantially all of our assets or enter into a merger or consolidation.
          Our credit facilities treatfacility treats a change of control as an event of default and also requirerequires us to maintain:

            •
            an interest coverage ratio that is not less than 2.75 to 1.0; and

            •
            maintain a debt coverage ratio whichthat will not be greater than 4.54.75 to 1.0 on all outstanding debt and 5.25 to 1.0 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition greater than $50 million).

          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 facilitiesfacility 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 our partnership agreement.available cash is not restricted. We are currently in compliance with the covenants contained in our credit facilitiesagreements and indentures.


          88

                  The average life of our long-term debt capitalization at December 31, 2003, was approximately 9 years. At the end of the year we had approximately $25.3 million of short-term working capital borrowings outstanding under our $425 million U.S. revolving credit facility, no amounts outstanding under our $125 million, 364-day revolving credit facility, no amounts outstanding under our $30 million Canadian working capital revolving credit facility, approximately $70.0 million outstanding under our $170 million Canadian revolving credit facility that matures in 2009, $200 million of senior notes that mature in 2012 and $250 million of senior notes that mature in 2013.

                  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


          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

          Contingencies
          See Note 11 to our gathering and marketing activities that can generally be described as high volume and low margin activities. 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. At December 31, 2003, we had received approximately $44.0 million of advance cash payments and prepayments from third parties to mitigate credit risk.

                  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. We have determined that we may have exceeded the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. On October 2, 2003, we submitted additional information to the BIS. 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, entitledAlfons Sperber v. Plains Resources Inc., et al. This suit, brought on behalf of a putative class of Plains All American Pipeline, L.P. common unit holders, asserts breach of fiduciary duty and breach of contract claims against the Partnership, 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. The Partnership intends to vigorously defend this lawsuit.

                  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 Items 1 and 2. "—Business and Properties—Regulation—Pipeline and Storage Regulation."

                  Regulatory compliance costs include those related to pipeline integrity management (these are recurring expenses estimated to be approximately $1.8 million in 2004) and the adoption by the DOT of API 653 as the standard for the inspection, repair, alteration and reconstruction of jurisdictional storage tanks (these are recurring expenses estimated to be approximately $2 million in 2004). We will continue to refine our estimates as information from initial assessments becomes available. 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 pipeline integrity regulations and API 653 standards. The timing of such additional costs is uncertain and could vary materially from our current projections.



                  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.

                  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. See Items 1 and 2. "Business and Properties—Operational Hazards and Insurance."

                  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.

            Capital Requirements

                  We have made and will continue to make capital expenditures for acquisitions and expansion 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 $51.2 million on expansion capital projects during 2004. These projects include $22.5 million on upgrades related to prior acquisitions, $10.0 million on the Cushing Phase IV expansion, $6.0 million on the Iatan System expansion, $4.5 million on information systems related projects and $8.2 million on other operations projects. In addition to these expansion projects, we expect to spend approximately $142.2 million for the pending acquisition of interests in the Capline and Capwood Pipeline systems ($158.0 million including the $15.8 million deposit made in December 2003). In April 2004, we will make the contingent payment related to the CANPET acquisition, as discussed in Note 7—"Partners' Capital and Distributions" in the "Notes to the Consolidated Financial Statements." We also estimate we will spend approximately $11.7 million in maintenance capital during 2004.

          Commitments

            

          		Commitments
          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-cancellable contractual


          obligations as of December 31, 2003, and our best estimate of the period in which the obligation will be settled (in millions):

           
          		 2004
          		 2005
          		 2006
          		 2007
          		 2008
          		 Thereafter
          		 Total
          Long-term debt $— $— $— $— $— $520.0 $520.0
          Operating leases(1)  12.7  11.2  8.8  5.3  2.8  0.7  41.5
          Capital expenditure obligations(2)  154.7  —  —  —  —  —  154.7
          Other long-term liabilities(3)(4)  10.9  3.2  1.2  0.6  0.4  0.7  17.0
            
          		 
          		 
          		 
          		 
          		 
          		 
           Total $178.3 $14.4 $10.0 $5.9 $3.2 $521.4 $733.2
          (1)
          Operating leases are primarily for office rent and trucks used in our gathering activities.

          (2)
          Includes approximately $142.2 million for the Capline Acquisition.

          (3)
          Approximately $10.9 million of the balance is related to the portion of our LTIP accrual that we anticipate settling with units in 2004.

          (4)
          Excludes approximately $11.0 million non-current liability related to SFAS 133.

                  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 madefrom third parties under contracts, thatthe majority of which 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 enterWe establish a margin for these purchases by entering into various types of physical and financial 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,through which we seek to maintain a position that is substantially balanced between crude oil and LPG purchases and sales and future delivery obligations. The volumetable below includes purchase obligations related to these activities. Where applicable, the amounts presented represent the net obligations associated with buy/sell contracts and pricesthose subject to a net settlement arrangement with the counterparty. We do not expect to use a significant amount of internal capital to meet these obligations, as the obligations will be funded by corresponding sales to creditworthy entities.

          The following table includes our best estimate of the amount and timing of these purchase and sale contracts are subject to market volatility and fluctuate with changes inpayments as well as others due under the NYMEX pricespecified contractual obligations as of crude oil from period to period. During 2003, these purchases averaged approximately $1.0 billion per month.

          December 31, 2006.

                                       
                              2012 and
          		 
            Total  2007  2008  2009  2010  2011  Thereafter 
            (In millions) 
           
          Long-term debt and interest payments(1) $5,181.6  $167.5  $167.5  $339.4  $159.2  $158.5  $4,189.5 
          Leases(2)  394.3   37.0   33.9   28.9   22.2   18.6   253.7 
          Capital expenditure obligations  11.5   11.5   —   —   —   —   — 
          Other long-term liabilities(3)  101.2   49.3   12.1   17.6   12.9   1.8   7.5 
                                       
          Subtotal  5,688.6   265.3   213.5   385.9   194.3   178.9   4,450.7 
          Crude oil and LPG purchases(4)  4,612.2   2,667.6   738.3   449.0   322.5   240.3   194.5 
                                       
          Total $10,300.8  $2,932.9  $951.8  $834.9  $516.8  $419.2  $4,645.2 
                                       
          (1)Includes debt service payments, interest payments due on our senior notes and the commitment fee on our revolving credit facility. Although there is an outstanding balance on our revolving credit facility at December 31, 2006 (this amount is included in the amounts above), we historically repay and borrow at varying amounts. As such, we have included only the maximum commitment fee (as if no amounts were outstanding on the facility) in the amounts above.
          (2)Leases are primarily for office rent and trucks used in our gathering activities.
          (3)Excludes approximately $21.4 million non-current liability related to SFAS 133 included in crude oil and LPG purchases.
          (4)Amounts are based on estimated volumes and market prices. The actual physical volume purchased and actual settlement prices may vary from the assumptions used in the table. Uncertainties involved in these estimates include levels of production at the wellhead, weather conditions, changes in market prices and other conditions beyond our control.
          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 periods of up to seventy-day periodsseventy days and are terminated upon completion of each transaction. At December 31, 2003,2006, we had outstanding letters of credit of approximately $57.9$185.8 million.
          Capital Contributions to PAA/Vulcan Gas Storage, LLC.  We and Vulcan Gas Storage are both required to make capital contributions in equal proportions to fund equity requests associated with certain projects specified in the joint venture agreement. For certain other specified projects, Vulcan Gas Storage has the right, but not the


          89

          obligation, to participate for up to 50% of such equity requests. In some cases, Vulcan Gas Storage’s obligation is subject to a maximum amount, beyond which Vulcan Gas Storage’s participation is optional. For any other capital expenditures, or capital expenditures with respect to which Vulcan Gas Storage’s participation is optional, if Vulcan Gas Storage elects not to participate, we have the right to make additional capital contributions to fund 100% of the project until our interest in PAA/Vulcan equals 70%. Such contributions would increase our interest in PAA/Vulcan and dilute Vulcan Gas Storage’s interest. Once PAA’s ownership interest is 70% or more, Vulcan Gas Storage would have the right, but not the obligation, to make future capital contributions proportionate to its ownership interest at the time. See Note 8 to our Consolidated Financial Statements.
          Distributions.  We willplan to 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 byin the discretion of our general partner for future requirements. On February 13, 2004,14, 2007, we paid a cash distribution of $0.5625$0.80 per unit on all outstanding units. The total distribution paid was approximately $35.2$104.6 million, with approximately $28.7$87.5 million paid to our common unitholders $4.2 million paid to our subordinated unitholders and $2.3approximately $17.1 million paid to our general partner for its general partner interest ($0.71.8 million) and incentive distribution interestsinterest ($1.615.3 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 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.



          We

          Upon closing of the Pacific acquisition, our general partner agreed to reduce the amounts of its incentive distributions commencing with the earlier to occur of (i) the payment date of the first quarterly distribution declared and paid $4.4after the closing date that equals or exceeds $0.80 per unit or (ii) the payment date of the second quarterly distribution declared and paid after the closing date. Such adjustment shall be as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. Pursuant to this agreement, the incentive distribution paid to the general partner on February 14, 2007 was reduced by $5 million. The total reduction in incentive distributions will be $65 million.
          In 2006, we paid $33.1 million in 2003.incentive distributions to our general partner. See Item 13. "Certain“Certain Relationships and Related Transactions—Transactions, and Director Independence — Our General Partner."

          ”

          Off-Balance Sheet Arrangements

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

          Risk Factors Related to Our Business

          The level ofinvested in certain entities (PAA/Vulcan, Butte, Settoon Towing and Frontier) that are not consolidated in our profitability is dependent upon an adequate supply of crude oilfinancial statements. In conjunction with these investments, 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. 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. 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.

          Potential future acquisitions and expansions, if any, may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations.

                  From time to time we evaluate and acquire assets and businesses that we believe complement our existing assets and businesses. Acquisitions may require substantial capital or the incurrence of substantial indebtedness. If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunityelect to evaluate the economic,provide financial and other relevant information that we will consider in determining the application of these funds and other resources.

          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, an average 10,000 barrel per day variance in the Basin Pipeline System, equivalent to an approximate 4% volume variance on that pipeline system, would result in an approximate $0.8 million change in annualized revenues less direct field operating costs.

          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 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. 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.

          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. A $0.01 per barrel variance in the aggregate average segment profit would have an approximate $2.0 million annual effect on segment profit.

          Newly acquired properties could expose us to environmental liabilities and increased regulatory compliance costs.

                  Our business plan calls for a continuing acquisition program. Assets that we have acquired or may acquire in the future will likely have associated environmental liabilities, as well as required compliance with regulations such as the integrity maintenance program for regulated pipelines and the API 653 standard for regulated storage. Although we attempt to identify such exposures and address the associated costs through indemnities, purchase price adjustments or insurance, we may experience costs not covered by indemnity, insurance or reserves.

          The profitability of our gathering and marketing activities depends primarily 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 $1.1 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.

          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.

          In 1999, we suffered a large loss from unauthorized crude oil trading by a former employee. A loss of this kind could occur again in the future in spite of our best efforts to prevent it.

                  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 not to acquire and hold crude oil, futures contracts or derivative products for the purpose of speculating on price changes. We discovered in November 1999 that this 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.

          Our operations are subject to federal and state environmental and safety laws and regulations relating to environmental protection and operational safety.

                  Our pipeline, gathering, storage and terminalling operations are subject to the risk of incurring substantial environmental and safety related costs and liabilities. These costs and liabilities could arise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or claims for damages to property or persons resulting from our operations. If we were not able to recover such resulting costs through insurance or increased tariffs and revenues, our cash flows and results of operations could be materially impacted.

                  The transportation and storage of crude oil results in a risk that crude oil and other hydrocarbons may be suddenly or gradually released into the environment, potentially causing substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages, and significant business interruption.

          Our Canadian pipeline assets are subject to federal and provincial regulation.

          ��       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 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.

          Cash distributions are not guaranteed and may fluctuate with our performance and the establishment of financial reserves.

                  Because distributions on the common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of the general partner. Cash distributions are dependent primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by non-cash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we records profits.

          The terms of our indebtedness may limit our ability to borrow additional funds, make distributions to unitholders, comply with the terms of our indebtedness or capitalize on business opportunities.

                  As of December 31, 2003, our total outstanding long-term debt was approximately $519.0 million. Our payment of principal and interest on the debt will reduce the cash available for distribution on the units. 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 outside the U.S., 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 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 distributions to our unitholders and our ability to make payments on our debt securities.

                  The after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. 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. Some or all of the distributions made to unitholders would be treated as dividend income, and no income, gains, losses or deductions would flow through to unitholders. Treatment of us as a corporation would cause a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of the common units. Moreover, treatment of us as a corporation would materially and adversely affect our ability to make payments on our debt securities.

                  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, franchiseguarantees or other forms of taxation. If any state werecredit support. See Note 9 to impose a tax upon usour Consolidated Financial Statements for more information concerning our obligations as an entity, the cash available for distributionthey relate to you would be reduced. The partnership agreement provides that, if a law is enacted or existing law is modified or interpretedour investment 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.


          PAA/Vulcan.

          Item 7A.    Quantitative and Qualitative Disclosures About Market Risks

          Item 7A.Quantitative and Qualitative Disclosures About Market Risk
          We are exposed to various market risks, including volatility in (i) crude oil, refined products, natural gas and LPG commodity prices, (ii) interest rates and (iii) currency exchange rates. We utilize various derivative instruments to manage such exposure.exposure and, in certain circumstances, to realize incremental margin during volatile market conditions. 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. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX, ICE andover-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


          90

          controls and procedures and certain aspects of corporate risk management. Our risk management function also approves all new risk management strategies through a formal process. With the exception of the controlled trading program discussed below, our approved strategies are intended to mitigate enterprise level risks that are inherent in our core businesses of gathering and marketing and storage. 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.

            Commodity Price Risk

          Commodity Price Risk
          We hedge our exposure to price fluctuations with respect to crude oil, refined products, natural gas and LPG in storage, and expected purchases sales and transportationsales of these commodities.commodities (relating primarily to crude oil and LPGs at this time). The derivative instruments utilized consist primarily of futures and option contracts traded on the NYMEX, ICE andover-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).companies. Our policy is to purchase only crude oilcommodity products for which we have a market, and to structure our sales contracts so that crude oil price fluctuations for those products 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 mightas these activities could expose us to indeterminablesignificant losses.

                  While

          Although we seek to maintain a position that is substantially balanced within our various commodity purchase and sales activities (which mainly relate to crude oil lease purchase and LPG activities,LPGs), 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 and an aggregate of 250,000 barrels of LPG.

                  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 gathering and marketing and storage.

          oil.

          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 receivemark-to-market treatment in current earnings, and result in greater potential for earnings volatility than in the past.volatility. This accounting treatment is discussed further under Note 2 "Summary of Significant Accounting Policies" in the "Notes to theour Consolidated Financial Statements."



          All of our open commodity price risk derivatives at December 31, 20032006 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 decreaseincrease are shown in the table below (in millions):

          below:
                  
             Effect of 10%
          		 
           Fair Value Price Increase 
           (In millions) 

          		 Fair Value
          		 Effect of 10% Price Decrease
          		 
          Crude oil:             
          Futures contracts $7.5 $(6.4) $(13.5) $(54.9)
          Swaps and options contracts $(3.3)$2.2  $(27.8) $(23.6)

          LPG:
           
           
           
           
           
          LPG and other:        
          Futures contracts $— $—  $(4.8) $5.9 
          Swaps and options contracts $(0.7)$0.9  $13.6  $0.7 
             
          Total Fair Value $(32.5)    
             
          The fair valuesvalue of the futures contracts areis based on quoted market prices obtained from the NYMEX.NYMEX or ICE. The fair value of the swaps and option contracts areis 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 used in these estimates as well as the source isfor the estimates are 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 anacross-the-board 10 percent decreaseincrease in price regardless of term or


          91

          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.

          Interest Rate Risk

          We utilizeuse 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 utilizeuse interest rate swaps and collars to hedge interest obligations on specific debt issuances, including anticipated debt issuances. In addition, in connection with the Pacific merger, we assumed interest rate swaps with an aggregate notional amount of $80 million. The interest rate swaps are a hedge against changes in the fair value of the 7.125% Senior Notes resulting from market fluctuations to LIBOR. 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%2006. All of our senior notes issued during 2002 and the 5.625% senior notes issued during 2003 are fixed rate notes and their interest rates arethus not subject to market risk. Our variable rate debt bears interest at LIBOR, prime or the bankers acceptance rate plus the applicable margin. The average interest rates presented below are based upon rates in effect at December 31, 2003.2006. 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 $125.8 $— $— $— $— $— $125.8 
            Average interest rate  2.3% —  —  —  —  —  2.3%
           Long-term debt—variable rate $— $— $— $— $— $70.0 $70.0 
            Average interest rate  —  —  —  —  —  2.2% 2.2%

                  Interest rate swaps are used to hedge underlying interest payment obligations. We estimate the fair value of these instruments based on current termination values. These instruments hedge interest rates



          on specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments.

                  The table shown below summarizes the fair value of our interest rate swaps by the year of maturity (in millions):

           
          		 Year of Maturity
          		 
           
          		 2004
          		 2005
          		 2006
          		 2007
          		 Total
          		 
          Interest rate swaps $(0.4)$— $— $— $(0.4)

                  At December 31, 2003, an interest rate swap with an aggregate notional principal amount of $50 million was outstanding. The interest rate swap is based on LIBOR rates, and provides for a LIBOR rate of 4.3% for a $50.0 million notional principal amount expiring March 2004. Interestthe credit spread on the underlying debt being hedged is based on LIBOR plus a margin.

            outstanding borrowings reflects market.

                                       
            Expected Year of Maturity 
            2007  2008  2009  2010  2011  Thereafter  Total 
            (Dollars in millions) 
           
          Liabilities:                            
          Short-term debt — variable rate $993.5  $—  $—  $—  $—  $—  $993.5 
          Average interest rate  5.8%  —   —   —   —   —   5.8%
          Currency Exchange Risk

          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 may 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 December 31, 2003, 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 December 31, 2003, we also had cross currency swap contracts for an aggregate notional principal amount of $23.0 million effectively converting this amount of our U.S. dollar denominated debt to $35.6 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1). The notional principal amount reduces by $2.0 million U.S. in May 2004 and May 2005 and has a final maturity in May 2006 ($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 $(0.3)$(0.1)$— $— $(0.4)
          Cross currency swaps  (1.0) (0.7) (3.1) —  (4.8)
            
          		 
          		 
          		 
          		 
          		 
          Total $(1.3)$(0.8)$(3.1)$— $(5.2)
            
          		 
          		 
          		 
          		 
          		 

          Item 8.    
                                   
            Year of Maturity 
            2007  2008  2009  2010  2011  Total 
           
          Forward exchange contracts $(2.0) $—  $—  $—  $—  $(2.0)
                                   
          Total $(2.0) $—  $—  $—  $—  $(2.0)
                                   

          Item 8.Financial Statements and Supplementary Data
          See “Index to the Consolidated Financial Statements and Supplementary Data

                  The information required here is included in the report as set forth in the "Index to Financial Statements"Statements” onpage F-1.



          Item 9.    Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

                  None.

          Item 9A.    Controls and Procedures

          Item 9.Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
          Not applicable.
          Item 9A.Controls and Procedures
          We maintain written "disclosure“disclosure controls and procedures,"” which we refer to as our "DCP."“DCP.” The purpose of our DCP is to provide reasonable assurance that (i) information is recorded, processed, summarized and reported in time to allow for timely disclosure of such information in accordance with the securities laws and SEC regulations


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          and (ii) information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure. Our DCP is incremental to our system of internal accounting controls designed to comply with the requirements of Section 13(b)(2) of the Exchange Act.

          Applicable SEC rules require an evaluation of the effectiveness of the design and operation of our DCP, as of December 31, 2003,DCP. Management, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Management (including our Chief Executive Officer, and Chief Financial Officer) has evaluated the effectiveness of the design and operation of our DCP as of December 31, 2003,2006, and has found our DCP to be effective in providing reasonable assurance of the timely recording, processing, summarization and reporting of information, and in accumulation and communication of information to management to allow for timely decisions with regard to required disclosure.

          In addition to the information concerning our DCP, we are required to disclose certain changes in our internal control over financial reporting. ThereAlthough we have made various enhancements to our controls during preparation for our assertion on internal control over financial reporting, there was no change in our internal control over financial reporting that occurred during the fourth quarter of 2003 and that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

          The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Actrules 13a-14(a) and15d-14(a) are filed with this report as exhibitsExhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. §13501350 are furnished with this report as exhibitsExhibits 32.1 and 32.2.


          Management is responsible for establishing and maintaining adequate internal control over financial reporting. “Internal control over financial reporting” is a process designed by, or under the supervision of, our Chief Executive Officer and our Chief Financial Officer, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our management, including our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our internal control over financial reporting as of December 31, 2006. See Management’s Report on Internal Control Over Financial Reporting onpage F-2.
          Item 9B.Other Information
          There was no information that was required to be disclosed in a report onForm 8-K

          during the fourth quarter of 2006 that has not previously been reported.


          PART III

          Item 10.    

          Item 10.Directors and Executive Officers of Our General Partner and Corporate Governance
          Directors and Executive Officers of Our General Partner

          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 (“GP LLC”), which employs our management and operational personnel.personnel (other than our Canadian personnel who are employed by PMC (Nova Scotia) Company). 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 are limited partners and do not directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to theour 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, ourOur general partner intendshas the sole discretion to incur indebtedness or other obligations on our behalf on a non-recourse basis.basis to the general partner.


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          Our partnership agreement provides that the general partner will manage and operate the partnershipus 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, the 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, theThe corporate governance of Plains All American GP LLC is, in effect, the corporate governance of the Partnership,our partnership, subject in all cases to any specific unitholder rights contained in theour partnership agreement. Specifically, our partnership agreement defines “Board of Directors” to mean the board of directors of GP LLC, which consists of up to eight directors elected by the members of GP LLC, and not by our unitholders. The Board currently consists of seven directors. Under the Second Amended and Restated Limited Liability Company Agreement of GP LLC (the “GP LLC Agreement”), three of the members of GP LLC have the right to designate one director each and our CEO is a director by virtue of holding the office. In addition, the GP LLC Agreement provides that three independent directors (and an eighth seat that is currently vacant) are elected, and may be removed, by a majority of the membership interest. The vacant seat is not required to be independent.
          In August 2005, a former member’s 19% interest in the general partner was sold pro rata to the other general partner owners, resulting in Vulcan Energy’s ownership interest increasing from 44% to 54%. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters — Beneficial Ownership of General Partner Interest.”
          In connection with this transaction, Vulcan Energy entered into an agreement with GP LLC pursuant to which Vulcan Energy has agreed to restrict certain of its voting rights to help preserve a balanced board. Vulcan Energy has agreed that, with respect to any action taken involving the election or removal of an independent director, Vulcan Energy will vote all of its interest in excess of 49.9% in the same way and proportionate to the votes of all membership interests other than Vulcan Energy’s. Without the voting agreement, Vulcan Energy’s ownership interest would allow Vulcan Energy, in effect, to unilaterally elect five of the eight board seats: the Vulcan Energy designee, the currently vacant seat and the three independent directors (subject, in the case of the independent directors, to the qualification requirements of the GP LLC Agreement, our partnership agreement, NYSE listing standards and SEC regulations). Vulcan Energy has the right at any time to give notice of termination of the agreement. The time between notice and termination depends on the circumstances, but would never be longer than one year. In connection with the August 2005 transaction, Messrs. Armstrong and Pefanis entered into waivers of the change in control provisions of their employment agreements, which otherwise would have been triggered by the transaction. These waivers were contingent upon Vulcan’s execution of the voting agreement, and will terminate upon any breach or termination by Vulcan Energy of, or notice of termination under, the voting agreement. See Item 11. “Executive Compensation — Employment Contracts” and “ — Potential Payments upon Termination orChange-in-Control.”
          Another member, Lynx Holdings I, LLC, also agreed to certain restrictions on its voting rights with respect to its approximate 1.2% interest in GP LLC and Plains AAP, L.P. The Lynx voting agreement requires Lynx to vote its membership interest (in the context of elections or the removal of an independent director) in the same way and proportionate to the votes of the other membership interests (excluding Vulcan’s and Lynx’s). Lynx has the right to terminate its voting agreement at any time upon termination of the Vulcan voting agreement or the sale or transfer of all of its interest in the general partner to an unaffiliated third party.
          Non-Management Executive Sessions and Shareholder Communications
          Non-management directors meet in executive session in connection with each regular board meeting. Each non-management director acts as presiding director at the regularly scheduled executive sessions, rotating alphabetically by last name.
          Interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary or Director of Internal Audit, Plains All American Pipeline, L.P., 333 Clay Street, Suite 1600, Houston, Texas 77002. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded.
          Independence Determinations and Audit Committee
          Because we are a limited partnership, the new listing standards of the New York Stock Exchange, when effective, willNYSE 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.


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          directors. We are, however, required to have an audit committee, and all of its members are required to be “independent” as defined by the NYSE.
          Under NYSE listing standards, to be considered independent, our board of directors must determine that a director has no material relationship with us other than as a director. The standards specify the criteria by which the independence of directors will be determined, including guidelines for directors and their immediate family members with respect to employment or affiliation with us or with our independent public accountants.
          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 membercharter of our audit committee is "independent" under applicable New York Stock Exchange Rulesavailable on our website. See “ — Meetings and (ii)Other Information.” The board of directors has determined that each member of our audit committee (Messrs. Goyanes, Smith and Symonds) is (i) “independent” under applicable NYSE rules and (ii) an "Audit“Audit Committee Financial Expert,"” as that term is defined in Item 401407 ofRegulation 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 Boardboard of Directorsdirectors considered the relationships described below:

          Mr. Everardo Goyanes,the Chairmanchairman of our Audit Committee,audit committee, is thePresident and Chief Executive Officer of Liberty Energy Corporation ("LEC"Holdings, LLC (“LEH”), a subsidiary of Liberty Mutual Insurance Company. Mr. Goyanes is an employee of Liberty Mutual Insurance Company. LECLEH makes investments in producing properties, from some of which Plains Marketing, L.P. buys the production. LECLEH does not operate the properties in which it invests. Plains Marketing pays the same amount per barrel to LECLEH that it pays to other interest owners in the properties. In 2003,2006, the amount paid to LECLEH by Plains Marketing was approximately $1,085,000 ($974,000 net$1.1 million (net of severance taxes),

          . The board has determined that the transactions with LEH are not material and do not compromise Mr. Goyanes’ independence.

          Mr. J. Taft Symonds,a member of our Audit Committee, isaudit committee, was a director and the non-executive Chairman of the Board of Tetra Technologies, Inc. ("Tetra"(“Tetra”). through December 2006. 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. Mr. Symonds is 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 iswas not an officer of Tetra, or Plains Resources, and doesdid not participate in operational decision-making,decision making, including decisions concerning selection of crude oil purchasers or entering into sales or marketing arrangements.

          In 2006, the amount paid to the Tetra subsidiary by Plains Marketing was approximately $14.0 million (net of severance taxes). The board has determined that the transactions with Tetra were not material and did not compromise Mr. Symonds’ independence.

          Mr. Arthur L. Smith,a member of our audit committee, has no relationships with either GP LLC or us, other than as a director and unitholder.
          Compensation Committee
          We have a compensation committee whichthat reviews and makes recommendations to the board regarding the compensation for the executive officers and administers our equity compensation plans for officers and key employees. We have a financeThe charter of our compensation committee that advisesis available on our website. See “— Meetings and assists managementOther Information.” The compensation committee currently consists of Messrs. Capobianco, Petersen and Sinnott. Under applicable stock exchange rules, none of the members of our compensation committee is required to be “independent.” None of the members of the compensation committee has been determined to be independent at this time. The compensation committee has the sole authority to retain any compensation consultants to be used to assist the committee, but did not retain any consultants in 2006. Similarly, the compensation committee has not delegated any of its authority to subcommittees. The compensation committee has delegated limited authority to the CEO to administer our long-term incentive plans with respect to financial matters. non-officers.
          Governance and Other Committees
          We also have a governance committee that is reviewing and revisingperiodically reviews our governance practices as appropriateguidelines. The charter of our governance committee is available on our website. See “— Meetings and Other Information.” The governance committee currently consists of Messrs. Smith and Symonds, each of whom is independent under the NYSE’s listing standards. As a limited partnership, we are not required by the listing standards of the NYSE to have a nominating committee. As discussed above, three of the owners of our general partner each have the right to appoint


          95

          a director, and Mr. Armstrong is a director by virtue of his office. In the event of a vacancy in lightthe three independent director seats, the governance committee will assist in identifying and screening potential candidates. Upon request of recentthe owners of the general partner, the governance reform initiatives. committee is also available to assist in identifying and screening potential candidates for the currently vacant “at large” seat. The governance committee will base its recommendations on an assessment of the skills, experience and characteristics of the candidate in the context of the needs of the board. As a minimum requirement for the independent board seats, any candidate must be “independent” and qualify for service on the audit committee under applicable SEC and NYSE rules.
          In addition, our partnership agreement provides for the establishment/establishment or 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. We currently haveSuch a standing conflicts committee consistingwould consist of a minimum of two members, who are notnone of whom can be officers or employees of our general partner or directors, officers or employees of its affiliates.affiliates nor owners of the general partner interest. 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.

                  We

          Meetings and Other Information
          During the last fiscal year our board of directors had eight regularly scheduled and special meetings, our audit committee had 14 meetings, our compensation committee had one meeting and our governance committee had two meetings. None of our directors attended fewer than 75% of the aggregate number of meetings of the board of directors and committees of the board on which the director served.
          As discussed above, the corporate governance of GP LLC is, in effect, the corporate governance of our partnership and directors of GP LLC are designated or elected by the members of GP LLC. Accordingly, unlike holders of common stock in a corporation, our unitholders have adoptedonly limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement. As a result, we do not hold annual meetings of unitholders.
          All of our committees have charters. Our committee charters and governance guidelines, as well as our Code of Business Conduct and our Code of Ethics for Senior Financial Officers. That code isOfficers, which apply to our principal executive officer, principal financial officer and principal accounting officer, are available on our website.

          Internet website at http://www.paalp.com. Print versions of the foregoing are available to any unitholder upon request by writing to our Secretary, Plains All American Pipeline, L.P., 333 Clay Street, Suite 1600, Houston, Texas 77002. We intend to disclose any amendment to or waiver of the Code of Ethics for Senior Financial Officers and any waiver of our Code of Business Conduct on behalf of an executive officer or director either on our Internet website or in an8-K filing. Our Chief Executive Officer submitted to the NYSE the most recent annual certification, without qualification, as required by Section 303A.12(a) of the NYSE’s Listed Company Manual.

          Report of the Audit Committee

          The audit committee of Plains All American GP LLC acting in its capacity as the general partner of Plains All American Pipeline, L.P. (the "Partnership"), oversees the Partnership'sPartnership’s financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls.

          In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this Annual Report onForm 10-K.

          The Partnership'sPartnership’s independent registered public accountants,accounting firm, PricewaterhouseCoopers LLP, areis responsible for expressing an opinion on the conformity of the audited financial statements with accounting principles generally accepted accounting principles.in the United States of America and opinions on management’s assessment and on the effectiveness of the Partnership’s internal control over financial reporting. The audit committee reviewed with PricewaterhouseCoopers LLP their judgment as to the quality, not just the acceptability, of the Partnership'sPartnership’s accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards.

          The audit committee discussed with PricewaterhouseCoopers LLP the matters required to be discussed by SAS 61 (Codification of Statement on Auditing Standards, AU § 380), as may be modified or supplemented. The


          96

          committee received written disclosures and the letter from PricewaterhouseCoopers LLP required by Independence Standards Board No. 1,Independence Discussions with Audit Committees, as may be modified or supplemented, and has discussed with PricewaterhouseCoopers LLP its independence from management and the Partnership.

          Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in the Annual Report onForm 10-K for the year ended December 31, 20032006 for filing with the SEC.

          Everardo Goyanes, Chairman



          Arthur L. Smith



          J. Taft Symonds

          Everardo Goyanes, Chairman
          Arthur L. Smith
          J. Taft Symonds
          Report of the Compensation Committee
          The compensation committee of Plains All American GP LLC reviews and makes recommendations to the board of directors regarding the compensation for the executive officers and directors.
          In fulfilling its oversight responsibilities, the compensation committee reviewed and discussed with management the compensation discussion and analysis contained in this Annual Report onForm 10-K. Based on the reviews and discussions referred to above, the compensation committee recommended to the board of directors that the compensation discussion and analysis be included in the Annual Report onForm 10-K for the year ended December 31, 2006 for filing with the SEC.
          David N. Capobianco, Chairman
          Gary R. Petersen
          Robert V. Sinnott
          Compensation Committee Interlocks and Insider Participation
          Messrs. Capobianco, Petersen and Sinnott served on the compensation committee during 2006. During 2006, none of the members of the committee was an officer or employee of us or any of our subsidiaries, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, none of the members of the compensation committee are former employees of ours or any of our subsidiaries. Messrs. Capobianco, Petersen and Sinnott are associated with business entities with which we have relationships. See Item 13. “Certain Relationships and Related Transactions, and Director Independence.”
          Directors and Executive Officers

          The following table sets forth certain information with respect to the members of our board of directors, our executive officers (for purposes of Item 401(b) ofRegulation S-K)and memberscertain other officers of us and our subsidiaries. Directors are elected annually and all executive officers are appointed by the board of directors to serve until their resignation, death or removal. There is no family relationship between any executive officer and director. Three of the Board of Directors of our general partner. Directors will serve until August 2004, and will be 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 2 to the following table.

          Name
          		Age
          		Position with Our General Partner
          Greg L. Armstrong(1) 45
          Age
          (as of
          Name
          		12/31/06)
          Position(1)
          Greg L. Armstrong*(2)48 Chairman of the Board, Chief Executive Officer and Director
          Harry N. PefanisPefanis* 4649 President and Chief Operating Officer
          Phillip D. KramerKramer* 4850 Executive Vice President and Chief Financial Officer
          George R. CoinerCoiner* 5356 Senior Group Vice President


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          Age
          (as of
          Name
          		12/31/06)
          Position(1)
          W. David DuckettDuckett* 4951 President—President — PMC (Nova Scotia) Company
          Mark F. ShiresShires* 4649 Senior Vice President—President — Operations
          Alfred A. Lindseth 3437 Senior Vice President—President — Technology, Process & Risk Management
          D. Mark Alenius47Vice President and Chief Financial Officer of PMC (Nova Scotia) Company
          Stephen L. Bart46Vice President — Operations of PMC (Nova Scotia) Company
          Ralph R. Cross51Vice President — Business Development and Transportation Services of PMC (Nova Scotia) Company
          Lawrence J. Dreyfuss52Vice President, General Counsel — Commercial & Litigation and Assistant Secretary
          Roger D. Everett61Vice President — Human Resources
          James B. Fryfogle55Vice President — Refinery Supply
          Mark J. Gorman52Vice President
          M.D. (Mike) Hallahan46Vice President — Crude Oil of PMC (Nova Scotia) Company
          Richard (Rick) Henson52Vice President — Corporate Services of PMC (Nova Scotia) Company
          Jim G. Hester 4447 Vice President—President — Acquisitions
          John Keffer47Vice President — Terminals
          Tim MooreMoore* 4649 Vice President, General Counsel and Secretary
          Tina L. ValDaniel J. Nerbonne 3549 Vice President—President — Engineering
          John F. Russell58Vice President — Pipeline Operations
          Robert Sanford57Vice President — Lease Supply
          Al Swanson42Vice President — Finance and Treasurer
          Tina L. Val*37Vice President — Accounting and Chief Accounting Officer
          Troy E. Valenzuela45Vice President — Environmental, Health and Safety
          John P. vonBerg*52Vice President — Trading
          David E. Wright61Vice President
          Ron F. Wunder38Vice President — LPG of PMC (Nova Scotia) Company
          David N. Capobianco(2)37Director and Member of Compensation** Committee
          Everardo Goyanes 5962 Director and Member of Audit* and Conflicts Committees* Committee
          Gary R. Petersen(1)Petersen(2) 5760 Director and Member of Compensation Committee*Committee
          John T. Raymond(1)Robert V. Sinnott(2) 3357 Director and Member of FinanceCompensation Committee
          Robert V. Sinnott(1)54Director and Member of Finance and Compensation Committees
          Arthur L. Smith 5154 Director and Member of Audit Conflicts*,and Governance* and Compensation* Committees

          98

          Age
          (as of
          Name
          		12/31/06)
          Position(1)
          J. Taft Symonds(1) 6467 Director and Member of Finance*,Audit and Governance and Audit CommitteeCommittees
          *
          Indicates chairman
          *  Indicates an “executive officer” for purposes of Item 401(b) of committee

          (1)
          The Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC (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., in which Mr. Raymond indirectly owns a limited partner interest. Sable Investments, L.P. is controlled by James M. Flores, the Executive Chairman of Plains Resources and also the Chairman and Chief Executive Officer of Plains Exploration and Production. 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. Symonds has been designated by Plains Resources, of which he is a director. See Item 12. "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Beneficial Ownership of General Partner Interest."

          Regulation S-K.

          ** Indicates chairman of committee.
          (1)Unless otherwise described, the position indicates the position held with Plains All American GP LLC.
          (2)The GP 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 three of the owners of our general partner each have the right to appoint a member of our board of directors. Mr. Capobianco has been appointed by Vulcan Energy Corporation, of which he is Chairman of the Board. Because it owns a majority in interest in GP LLC, Vulcan Energy Corporation has the power at any time to cause an additional director to be elected to the currently vacant board seat. Mr. Petersen has been appointed byE-Holdings III, L.P., an affiliate of EnCap Investments L.P., of which he is Senior Managing Director. Mr. Sinnott has been appointed by KAFU Holdings, L.P., which is affiliated with Kayne Anderson Investment Management, Inc., of which he is President. See Item 12. “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.formation in 1998. 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 Inc. 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 National Oilwell Varco, Inc., a director of Breitburn Energy Partners, L.P. and a director of PAA/Vulcan.


          Harry N. Pefanis has served as President and Chief Operating Officer since our formation.formation in 1998. He was also a director of our former general partner. In addition, he was Executive Vice President—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—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.

          formation. Mr. Pefanis is also a director of PAA/Vulcan and Settoon Towing.

          Phillip D. Kramer has served as Executive Vice President and Chief Financial Officer since our formation.formation in 1998. 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 in 1998 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.formation. Prior to joining Plains Marketing & Transportation Inc., he was Senior Vice President, Marketing with Scurlock Permian Corp.

          LLC. Mr. Coiner is also a director of Settoon Towing.

          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. sincefrom 1985 to 2001, where he served in various capacities, including most recently as President, Chief Executive Officer and Chairman of the Board. Mr. Duckett is also a director of WellPoint Systems Inc.

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          Mark F. Shires has served as Senior Vice President—President — Operations since June 2003 and as Vice President—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—President — Technology, Process & Risk Management since June 2003 and as Vice President—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 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.

                  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.

                  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.

                  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 Nuevo Energy Company and Equus II Incorporated.

                  John T. Raymond has served as a director since June 2001. Mr. Raymond has served as President and Chief Executive Officer of Plains Resources Inc. since December 2002 and is President and Chief Operating Officer of Plains Exploration and Production. 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. 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 Plains Resources and Glacier Water Services, Inc. (a vended water company).

                  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 and Cabot Oil & Gas Corporation and is a current director of Evergreen Resources, Inc. Mr. Smith holds the CFA designation. 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 has been Chairman of the Board of Symonds Trust Co. Ltd. (an investment firm) and Chairman of the Board of Maurice Pincoffs Company, Inc. (an international marketing firm) since 1978. He is also Chairman of the Board of Tetra Technologies, Inc. (an oilfield services firm) and a director of Plains Resources Inc. Mr. Symonds has a background in both investment and commercial banking. 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 Diamond31Manager—Special Projects
          Lawrence J. Dreyfuss49Vice 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.)
          Al Swanson40Vice President and Treasurer
          Troy Valenzuela43Vice President—Environmental, Health and Safety
          John P. vonBerg49Vice President—Trading
          Canadian Officers:
          D. Mark Alenius44Vice President and Chief Financial Officer of PMC (Nova Scotia) Company
          Ralph R. Cross49Vice President—Business Development of PMC (Nova Scotia) Company
          Ronald H. Gagnon46Vice President—Operations of PMC (Nova Scotia) Company
          M.D. (Mike) Hallahan43Vice President—Crude Oil of PMC (Nova Scotia) Company
          Ron F. Wunder36Vice 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.

                  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.

                  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.

                  Troy 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 the partnership and its predecessors for the last 10 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 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 1992 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.

          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 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’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.

          Stephen L. Bart has been Vice President, Operations of PMC (Nova Scotia) Company since April 2005 and was Managing Director, LPG Operations & Engineering from February to April 2005. From June 2003 to February 2005, Mr. Bart was engaged as a principal of Broad Quay Development, a consulting firm. From April 2001 to June 2003, Mr. Bart served as Chief Executive Officer of Novera Energy Limited, a publicly-traded international renewable energy concern. From January 2000 to April 2003, he served as Director, Northern Development, for Westcoast Energy Inc.
          Ralph R. Cross has been Vice President of Business Development and Transportation Services 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. GagnonLawrence J. Dreyfusshas beenserved as Vice President, OperationsGeneral Counsel — Commercial & Litigation and Assistant Secretary since August 2006. Mr. Dreyfuss was Vice President, Associate General Counsel and Assistant Secretary of PMC (Nova Scotia) Companyour general partner from February 2004 to August 2006 and 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 January 2004,May 1999. In addition, he was a Vice President of Scurlock Permian LLC from 1987 to 1999.
          Roger D. Everett has served as Vice President — Human Resources since November 2006 and as Director of Human Resources from August 2006 to December 2006. Before joining us, Mr. Everett was a Principal with Stone Partners, a human resource management consulting firm, for over 10 years serving as the Managing Director Information and Transportation ServicesHuman Resources from June 20032000 to January 2004 and Director, Information Services from July 2001 to May 2003.2006. Mr. Gagnon was previously with CANPET Energy Group Inc.Everett has held numerous positions of increasing responsibility in human resource management since 1987, where he served in various capacities,1979 including Vice President Producer Services.of Human Resources at Living Centers of America and Beverly Enterprises, Director of Human Resources at Healthcare International and Director of Compensation and benefits at Charter Medical.
          James B. Fryfogle has served as Vice President — Refinery Supply since March 2005. He served as Vice President — Lease Operations from July 2004 until March 2005. Prior to joining us 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.
          Mark J. Gorman has served as Vice President since November 2006. Prior to joining Plains, he was with Genesis Energy in differing capacities as a Director, President and CEO, and Executive Vice President and COO


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          from 1996 through August 2006. From 1992 to 1996, he served as a President for Howell Crude Oil Company. Mr. Gorman began his career with Marathon Oil Company, spending 13 years in various disciplines.
          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.Inc. where he served in various capacities since 1996, most recently as General Manager, Facilities.
          Richard (Rick) Hensonjoined PMC (Nova Scotia) Company in December 2004 as Vice President of Corporate Services. Mr. Henson was previously with Nova Chemicals Corporation, serving in various executive positions from 1999 through 2004, including Vice President, Petrochemicals and Feedstocks, and Vice President, Ethylene and Petrochemicals Business.
          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.
          John Keffer has served as Vice President — Terminals since November 2006. Mr. Keffer joined Plains Marketing L.P. in October 1998 and prior to his appointment as Vice President, he served as Managing Director — Refinery Supply, Director of Trading and Manager of Sales and Trading. Prior to joining Plains Mr. Keffer was with Prebon Energy, an energy brokerage firm, from January 1996 through September 1998. Mr. Keffer was with the Permian Corporation / Scurlock Permian from January 1990 through December 1995, where he served in several capacities in the marketing department including Director of Crude Oil Trading. Mr. Keffer began his career with Amoco Production Company and served in various capacities beginning in June 1982.
          Tim Moorehas 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.
          Daniel J. Nerbonne has served as Vice President — Engineering since February 2005. Prior to joining us, Mr. Nerbonne was General Manager of Portfolio Projects for Shell Oil Products US from January 2004 to January 2005 and served in various capacities, including General Manager of Commercial and Joint Interest, with Shell Pipeline Company or its predecessors from 1998. From 1980 to 1998 Mr. Nerbonne held numerous positions of increasing responsibility in engineering, operations, and business development, including Vice President of Business Development from December 1996 to April 1998, with Texaco Trading and Transportation or its affiliates.
          John F. Russell has served as Vice President — Pipeline Operations since July 2004. Prior to joining us, 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.
          Robert Sanford has served as Vice President — Lease Supply since June 2006. He served as Managing Director — Lease Acquisitions and Trucking from July 2005 to June 2006 and as Director of South Texas and Mid Continent Business Units from April 2004 to July 2005. Mr. Sanford was with Link Energy/EOTT Energy from 1994 to April 2004, where he held various positions of increasing responsibility.
          Al Swanson has served as Vice President — Finance and Treasurer since August 2005, as Vice President and Treasurer from February 2004 to August 2005 and as Treasurer from May 2001 to February 2004. In addition, he held 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,


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          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 since 1992. He was Director of EH&S with Plains Resources from January 1996 to June 2002, and Manager of EH&S from July 1992 to 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 — Trading since May 2003 and Director of these activities since joining us in January 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 E. Wright has served as Vice President since November 2006. Prior to joining Plains, he served as Executive Vice President, Corporate Development for Pacific Energy Partners, L.P. from February 2005 and as Vice President, Corporate Development and Marketing from December 2001. Mr. Wright also served as Vice President, Distribution West of Tosco Refining Company from March 1997 to June 2001, and as Vice President, Pipelines for GATX Terminals Corporation from October 1995 to March 1997.
          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.
          David N. Capobianco has served as a director of our general partner since July 2004. Mr. Capobianco is Chairman of the board of directors of Vulcan Energy Corporation and a Managing Director and co-head of Private Equity of Vulcan Capital, an affiliate of Vulcan Inc., where he has been employed since April 2003. Previously, he served as a member of Greenhill Capital from 2001 to April 2003 and Harvest Partners from 1995 to 2001. Mr. Capobianco is Chairman of the board of Vulcan Resources Florida, and is a director of PAA/Vulcan and ICAT Holdings. Mr. Capobianco received a BA in Economics from Duke University and an MBA from Harvard.
          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 of our general partner since June 2001. Mr. Petersen is Senior Managing Director of EnCap Investments L.P., an investment management firm which he co-founded in 1988. He is also a director of EV Energy Partners, L.P. 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 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.
          Robert V. Sinnott has served as a director of our general partner or former general partner since September 1998. Mr. Sinnott is President, Chief Investment Officer and Senior Managing Director of energy investments of Kayne Anderson Capital Advisors, L.P. (an investment management firm). He also served as a Managing Director from 1992 to 1996 and as a Senior Managing Director from 1996 until assuming his current role in 2005. He is also


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          President of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. and he is a director of Kayne Anderson Energy Development Company. He was Vice President and Senior Securities Officer of the Investment Banking Division of Citibank from 1986 to 1992. Mr. Sinnott received a BA from the University of Virginia and an MBA from Harvard.
          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 holds the CFA designation. He serves on the board of non-profit Dress for Success Houston and the Board of Visitors for the Nicholas School of the Environment and Earth Sciences at Duke University. 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 of our general partner since June 2001. Mr. Symonds is Chairman of the Board of Symonds Trust Co. Ltd. (a private investment firm) and was, until December 2006, Chairman of the Board of Tetra Technologies, Inc. (an oil and gas 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 has a background in both investment and commercial banking, including merchant banking in New York, London and Hong Kong with Paine Webber, Robert Fleming Group and Banque de la Societe Financiere Europeenne. He is Chairman of the Houston Arboretum and Nature Center. Mr. Symonds received a BA from Stanford University and an MBA from Harvard.
          Section 16(a) Beneficial Ownership Reporting Compliance

          Section 16(a) of the Securities and Exchange Act of 1934 requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC and the New York Stock ExchangeNYSE initial reports of ownership and reports of changes in ownership of such equity securities. Such persons are also required to furnish us with copies of all Section 16(a) forms that they file. Such reports are accessible on or through our Internet website at http://www.paalp.com.
          Based solely upon a review of the copies of Forms 3, 4 and 5 furnished to us, or written representations from certain reporting persons that no Forms 5 were required, we believe that our executive officers and directors complied with all filing requirements with respect to transactions in our equity securities during 2003, except2006.
          Item 11.Executive Compensation
          Compensation Discussion and Analysis
          Background
          All of our officers and employees (other than Canadian personnel) are employed by Plains All American GP LLC. Our Canadian personnel are employed by PMC (Nova Scotia) Company, which is a wholly owned subsidiary. Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all employment-related costs, including compensation for executive officers.
          Objectives
          Since our inception, we have employed a compensation philosophy that emphasizes pay for performance, both on an individual and entity level, and places the majority of each Named Executive Officer’s (defined below) compensation at risk. The primary long-term measure of the Partnership’s performance is its ability to increase its sustainable quarterly distribution to its unitholders. We believe ourpay-for-performance approach aligns the interests of executive officers with that of our unitholders, and at the same time enables us to maintain a lower level of base overhead in the event our operating and financial performance is below expectations. Our executive compensation is designed to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interest with that of our unitholders, and to reward success in reaching such goals. We use three primary elements of compensation to fulfill that design — salary, cash bonus and long-term


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          equity incentive awards. In practice, our salaries are moderate relative to the broad spectrum of energy industry competitors for similar talent, but are generally competitive with the narrower universe of large-cap MLP peers. The determination of specific individuals’ cash bonus is based on their relative contribution to achieving or exceeding annual goals and the determination of specific individuals’ long-term incentive awards is based on their expected contribution in respect of longer term performance benchmarks. Cash bonuses and equity incentives (as opposed to salary) represent the truly performance-driven elements. They are also flexible in application and can be tailored to serve more than one purpose. We do not maintain a defined benefit or pension plan for our executive officers as we believe such plans primarily reward longevity and not performance. We provide a basic benefits package generally to all employees, which includes a 401(k) plan and health, disability and life insurance. In instances considered necessary for the execution of their job responsibilities, we also reimburse certain of our executive officers and other employees for club dues and similar expenses. We consider these benefits and reimbursements to be typical of other employers, and we do not believe they are distinctive of our compensation program.
          Elements of Compensation
          Salary.  We do not “benchmark” our salary or bonus amounts. In practice, our salaries are moderate relative to the broad spectrum of energy industry competitors for similar talent, but are generally competitive with the narrower universe of large-cap MLP peers.
          Cash Bonuses.  Our cash bonuses consist of annual discretionary bonuses in which all Named Executive Officers potentially participate and a formula-based quarterly bonus program in which Messrs. Coiner and vonBerg participate.
          Long-Term Incentive Awards.  The primary long-term measure of the Partnership’s performance is its ability to increase its sustainable quarterly distribution to its equity holders. The Partnership uses performance-indexed phantom unit grants to encourage and reward timely achievement of targeted distribution levels and align the long-term interests of the Named Executive Officers with those of the Partnership’s equity owners. These grants also contain minimum service periods as further described below in order to encourage long-term retention. A phantom unit is the right to receive, upon the satisfaction of any vesting criteria specified in the grant, a common unit (or cash equivalent) of the Partnership. The Partnership does not use options as a form of incentive compensation. Unlike “vesting” of an option, vesting of a phantom unit results in delivery of a common unit or cash of equivalent value as opposed to a right to exercise. Terms of historical phantom unit grants have varied, but generally phantom units vest upon the later of achievement of targeted distribution threshold levels and continued employment for periods ranging from two to six years. These distribution performance thresholds are generally consistent with the Partnership’s targeted range for distribution growth. To encourage accelerated performance, if the Partnership meets certain distribution thresholds prior to meeting the minimum service requirement for vesting, the named executive officers have the right to receive distributions on phantom unit grants prior to vesting in the underlying units (referred to as distribution equivalent rights, or “DERs”).
          Relation of Compensation Elements to Compensation Objectives
          Our compensation program is designed to motivate, reward and retain our executive officers. Cash bonuses serve as a near-term motivation and reward for achieving the annual goals established at the beginning of each year. Phantom unit awards and associated DERs provide motivation and reward over both the near-term and long-term for achieving performance thresholds necessary for vesting. The level of annual bonus and phantom unit awards reflect the moderate salary profile and the significant weighting towards performance-based, at-risk compensation. Salaries and cash bonuses (particularly quarterly bonuses), as well as currently payable DERs associated with unvested phantom units, serve as near-term retention tools. Longer-term retention is facilitated by the minimum service periods of up to five years associated with phantom unit awards and, in the case of Mr. Coiner and Mr. vonBerg, annual bonuses that are payable over a three-year period. To facilitate the compensation committee in reviewing and making recommendations with respect to compensation of Named Executive Officers, the committee is provided a compensation “tally sheet” for such officers.
          We stress performance-based compensation elements to attempt to create a performance-driven environment in which our executive officers are (i) motivated to perform over both the short term and the long term,


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          (ii) appropriately rewarded for their services and (iii) encouraged to remain with the Partnership even after meeting long-term performance thresholds in order to meet the minimum service periods and by the promise of rewards yet to come. We believe our compensation philosophy as implemented by application of the three primary compensation elements aligns the interests of the Named Executive Officers with our equity holders and positions the Partnership to achieve its business goals.
          We believe these compensation practices have been successful in achieving our objectives. Over the five-year period ended December 31, 2006, our annual distribution per limited partner unit has grown at a compound annual rate of 8.3% and the total return realized by our limited partner unitholders for that period averaged approximately 23%. Our retention rate for Named Executive Officers over the same period has been 100%.
          Application of Compensation Elements
          Salary.  We do not make systematic annual adjustments to the salaries of the Named Executive Officers. Instead, when indicated as a result of adding new senior management members to keep pace with our overall growth, necessary salary adjustments are made to maintain hierarchical relationships between senior management levels and the new senior management members. Since May 1999, Messrs. Armstrong and Pefanis have received one salary adjustment and Messrs. Coiner and Kramer have received two salary adjustments.
          Cash Bonuses.
          Annual Discretionary Bonuses.  Annual discretionary bonuses are determined based on the Partnership’s performance relative to its annual plan forecast and public guidance, its distribution growth targets and other quantitative and qualitative goals established at the beginning of each year. Such annual objectives are discussed and reviewed with the board in conjunction with the review and authorization of the annual plan.
          At the end of each year, our CEO performs a quantitative and qualitative assessment of the Partnership’s performance relative to its goals. Key quantitative measures include earnings before interest, taxes, depreciation and amortization, excluding items affecting comparability (“EBITDA”), relative to established guidance, as well as the growth in the annualized quarterly distribution level per limited partner unit relative to annual growth targets. Our primary performance metric is our ability to generate increasing and sustainable cash distributions to our equity owners. Accordingly, although net income and net income per unit are monitored to highlight inconsistencies with primary performance metrics, as is the Partnership’s market performance relative to our MLP peers and major indices, these metrics are considered secondary performance measures. Our CEO’s written analysis of our performance examines the Partnership’s accomplishments, shortfalls and overall performance against opportunity, taking into account controllable and non-controllable factors encountered during the year.
          The resulting document and supporting detail is submitted to our board of directors for review and comment. Based on the conclusions set forth in the annual performance review, our CEO submits recommendations to the compensation committee for bonuses to Named Executive Officers, taking into account the relative contribution of the individual officer. Except as described below for Messrs. Coiner and vonBerg, there are no set formulas for determining the annual discretionary bonus for Named Executive Officers. Factors considered by our CEO in determining the level of bonus in general include (i) whether or not we achieved the goals established for the year and any notable shortfalls relative to expectations; (ii) the level of difficulty associated with achieving such objectives based on the opportunities and challenges encountered during the year; (iii) current year operating and financial performance relative to both public guidance and prior year’s performance; (iv) significant transactions or accomplishments for the period not included in the goals for the year; (v) our relative prospects at the end of the year with respect to future growth and performance; and (vi) our positioning at the end of the year with respect to our targeted credit profile. Our CEO takes these factors into consideration as well as the relative contributions of each of the Named Executive Officers to the year’s performance in developing his recommendations for bonus amounts.
          These recommendations are discussed with the compensation committee, adjusted as appropriate, and submitted to the board for its review and approval. Similarly, the compensation committee assesses the CEO’s contribution toward meeting the Partnership’s goals, and recommends a bonus for the CEO it believes to be commensurate with such contribution. In several instances, the CEO has requested that the bonus amount


          105

          recommended by the compensation committee be reduced to maintain a closer relationship to bonuses awarded to the other Named Executive Officers.
          Quarterly Bonus based on Adjusted EBITDA.  Mr. Coiner, Mr. vonBerg and certain other members of our U.S. based senior management team are directly involved in activities that generate earnings for the Partnership. These individuals, along with approximately 80 other employees in our marketing and business development groups participate in a quarterly bonus pool based on adjusted EBITDA,1 which directly rewards for quarterly performance the commercial and asset-managing employees who participate. This quarterly incentive provides a direct incentive to optimize quarterly performance even when, on an annual basis, other factors might negatively affect bonus potential. Allocation of quarterly bonus amounts among all participants based on relative contribution is recommended by Mr. Coiner and reviewed, modified and approved by Mr. Pefanis, as appropriate. Mr. Pefanis does not participate in the quarterly bonus. The quarterly bonus amounts for Mr. Coiner and Mr. vonBerg are taken into consideration in determining the recommended annual discretionary bonus submitted by the CEO to the compensation committee.
          Long-Term Incentive Awards.  The Partnership does not make systematic annual phantom unit awards to the Named Executive Officers. Instead, our objective is to time the granting of awards such that as performance thresholds are met for existing awards, additional long-term incentives are created. Thus, performance is rewarded by relatively greater frequency of awards and lack of performance by relatively lesser frequency of awards. Generally, we believe that a three- to four-year grant cycle (and extended time-vesting requirements) provides a balance between a meaningful retention period for us and a visible, reachable reward for the executive officer. Achievement of performance targets does not shorten the minimum service period requirement. If top performance targets on outstanding awards are achieved in the early part of this four-year cycle, new awards are granted with higher performance thresholds, and the minimum service periods of the new awards are generally synchronized with the remaining time-vesting requirements of outstanding awards in a manner designed to encourage extended retention of the Named Executive Officers. Accordingly, these new arrangements inherently take into account the value of awards where performance levels have been achieved but have not yet vested due to ongoing service period requirements, but do not take into consideration previous awards that have fully vested.
          Application in 2006
          At the beginning of 2006, the Partnership publicly established the following five goals for 2006:
          1. Deliver operating and financial performance in line with guidance furnished at the beginning of 2006 on aForm 8-K dated February 23, 2006;
          2. Maintain and improve our present credit rating and further expand our liquidity and financial flexibility to accommodate future growth;
          3. Optimize our existing asset base and operations and expand our inventory of internal expansion projects;
          4. Pursue our target of averaging $200 to $300 million of accretive and strategic acquisitions; and
          5. Increase our distribution paid to unitholders by 10% over 2005 payments.
          The Partnership met or substantially exceeded each of these goals in 2006. Excluding the impact of unforecasted acquisitions, our adjusted EBITDA exceeded the original guidance for 2006 by approximately 24%. Including the impact of unforecasted acquisitions, our adjusted EBITDA exceeded original guidance for 2006 by approximately 40%. We exceeded our acquisition target for 2006 by completing seven acquisitions aggregating approximately $3.0 billion. We also took several steps to optimize our asset base and expand our inventory of organic growth projects as we successfully implemented an expanded capital program totaling approximately $332 million, an increase of 44% as compared to the original capital program for 2006 of approximately
          1 Adjusted EBITDA excludes the effect of certain non-cash items such as the effect of FAS 133 and accrual of LTIP expenses. Any bonus amounts that are deducted in calculating EBITDA are added back for purposes of calculating the bonus pool.


          106

          $230 million. Despite a year of significant acquisition and expansion activity, we maintained a strong capital structure and an investment grade credit rating and expanded the Partnership’s liquidity and financial flexibility. Finally, we exceeded our goal for unitholder distributions as total distributions paid in 2006 increased by approximately 11.5% over distributions paid in 2005. The total return to our limited partners (unit price appreciation plus distributions received) was approximately 38% in 2006 as compared to 25.8%, 15.8% and 19.0% for the MLP peer index, the S&P 500 and the Dow Jones Industrial Index, respectively.
          For 2006, the elements of compensation were applied as follows:
          Salary.  No salary adjustments were recommended or made in 2006.
          Cash Bonuses.  Based on our CEO’s annual performance review and the individual performance of each of our Named Executive Officers, our compensation committee recommended to the board and the board approved the annual bonuses reflected in the “Summary Compensation Table” and notes thereto. The aggregate annual and, where applicable, quarterly bonus amounts reflected in the Summary Compensation Table are approximately 11% to 28% higher than amounts paid in 2005, which was considered a year of strong performance. Such amounts take into account the significant overperformance relative to each of the five goals established for 2006, the absence of any notable shortfalls relative to expectations; the level of difficulty associated with achieving such objectives; our relative positioning at the end of the year with respect to future growth and performance; the significant transactions or accomplishments for the period not included in the goals for the year; and our positioning at the end of the year with respect to our targeted credit profile. In the case of Mr. Coiner and Mr. vonBerg, the aggregate bonus amount represented 39.8% and 37.5% in annual bonus and 60.2% and 62.5% in quarterly bonus, respectively.
          Long-Term Incentive Awards.  No awards were made in 2006. Effective with the November 2006 distribution, however, we achieved the highest performance threshold ($3.00 per limited partner unit annualized) contained in substantially all pre-2006 phantom unit awards. Vesting of these pre-2006 awards remains subject to continued employment, and the service-period vesting requirements will be met in various increments over the next three to four years with the final vesting in May 2010. The compensation expense recognized in 2006 related to such awards is reflected on an individual basis in the Summary Compensation Table that follows. The vesting requirements are described in the footnotes to the Outstanding Equity Awards Table that follows.
          Consistent with our policy of issuing new grants (with extended time-vesting periods) when the highest performance threshold of existing grants has been reached, in February of 2007 our board of directors granted awards with a top performance threshold of $4.00 per limited partner unit, representing a 33% increase over the November 2006 distribution level of $3.00 per unit. Such grants are intended to encourage continued growth and fundamental performance that will support future distribution growth. Specifically, the terms of the awards provide that, subject to meeting the service period requirement, the phantom unit grants will vest in one-third increments upon achieving annualized quarterly distribution levels of $3.50 per unit, $3.75 per unit and $4.00 per unit, respectively. Tandem DERs vest in 25% increments upon achieving annualized quarterly distribution levels of $3.40, $3.60, $3.80 and $4.00 per unit. Approximately two-thirds of the awards are eligible to vest in 2011 and one-third are eligible to vest in 2012. If any of the performance thresholds are not achieved prior to the May 2014 distribution date, such awards will expire. Upon vesting, the phantom units are payable on a one-for-one basis in common units of the partnership (or cash equivalent depending on the form of grant). The 2007 awards included grants to the Named Executive Officers as follows: Mr. Petersen filedArmstrong, 180,000; Mr. Pefanis, 120,000; Mr. Kramer, 60,000; Mr. Coiner, 90,000 and Mr. vonBerg, 54,000. The number of phantom units awarded to the Named Executive Officers represents approximately 60% of their outstanding pre-2006 awards.
          Other Compensation Related Matters
          Equity Ownership.  As of December 31, 2006, each of the Named Executive Officers owned substantial equity in the partnership. Although the Partnership encourages its Named Executive Officers to retain ownership in the Partnership, it does not have a policy requiring maintenance of a specified equity ownership level. The Partnership’s policies prohibit the Named Executive Officers from using puts, calls or options to hedge the


          107

          economic risk of their ownership. In the aggregate, as of December 31, 2006, the Named Executive Officers beneficially owned an Amended Form 4 to amend two previous Forms 4 that were otherwise timely filed. Mr. Petersen reported two acquisitionsaggregate of approximately 556,475 limited partner units, excluding any unvested equity awards, as well as an aggregate 3% indirect beneficialownership interest in the general partner. Based on the market price of the limited partner units at December 31, 2006 and an implied valuation for their collective general partner interest using similar valuation metrics, the value of the equity ownership of 1,250 units on June 8, 2002these individuals was approximately 45 times their aggregate 2006 salaries and June 8, 2003,

          approximately 3.9 times the combined aggregate salaries and bonuses for 2006.


          respectively,

          Recovery of Prior Awards.  Except as provided by applicable laws and regulations, the Partnership does not have a policy with respect to adjustment or recovery of awards or payments if relevant company performance measures upon which previous awards were based are restated or otherwise adjusted in a manner that would reduce the size of such award or payment.
          Section 162(m).  With respect to the deduction limitations under Section 162(m) of the Code, Plains is a limited partnership and does not meet the definition of a “corporation” under Section 162(m). Nonetheless, the salaries for each of the Named Executive Officers are substantially less than the Section 162(m) threshold of $1,000,000 and we believe the bonus compensation and long-term incentive compensation would qualify for performance-based compensation under Reg. 1.162-27(e) and therefore would not be additive to salaries for purposes of measuring the $1,000,000 tax limitation.
          Change in Control Triggers.  The employment agreements for Messrs. Armstrong and Pefanis and the long-term incentive plan grants to the Named Executive Officers include severance payment provisions or accelerated vesting triggered upon a change of control, as defined in the respective agreement. In the case of the long-term incentive plan grants, the provision becomes operative only if the change in control is accompanied by a change in status (such as the termination of employment by the transfergeneral partner). We believe this “double trigger” arrangement is appropriate because it provides assurance to the executive, but does not offer a windfall to the executive when there has been no real change in employment status. The provisions in the employment agreements for Messrs. Armstrong and Pefanis become operative only if the executive terminates employment within three months of such unitsthe change in control. Messrs. Armstrong and Pefanis agreed to EnCap Energy Capital Fund III, L.P., which is controlled by EnCap Investments L.P.,a conditional waiver of which Mr. Petersen isthese provisions with respect to a Managing Director. Mr. Petersen disclaims beneficial ownership of such units.

          transaction in 2005 that would have constituted a change in control. See ‘‘— Potential Payments upon Termination orItem 11.    Change-in-Control” and “— Employment Agreements.”

          Executive Compensation

          Summary Compensation Table

          The following table sets forth certain compensation information for our Chief Executive Officer, Chief Financial Officer and the fourthree other most highly compensated executive officers in 20032006 (the "Named“Named Executive Officers"Officers”). Messrs. Armstrong, Pefanis and Kramer were compensated by Plains Resources prior to July 2001. However, weWe 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 allocablecompensation.
          2006 Summary Compensation Table
                                       
                    Non-Equity
          		    
                  Stock
          		 Incentive Plan
          		 All Other
          		  
              Salary
          		 Bonus
          		 Awards
          		 Compensation
          		 Compensation
          		 Total
          Name and Principal Position
          		 Year ($) ($) ($)(1) ($) ($)(2) ($)
           
          Greg L. Armstrong  2006   375,000   3,750,000   5,184,222   0   15,930   9,325,152 
          Chairman and CEO                            
          Harry N. Pefanis  2006   300,000   3,400,000   3,456,148   0   15,930   7,172,078 
          President and Chief Operating Officer                            
          Phillip D. Kramer  2006   250,000   1,000,000   1,876,043   0   15,930   3,141,973 
          Executive Vice President and
          Chief Financial Officer          		                            
          George R. Coiner  2006   250,000   3,390,100(3)  2,616,477   0   15,930   6,272,507 
          Senior Group Vice President                            
          John P. vonBerg  2006   200,000   2,934,700(4)  1,575,530   0   15,744   4,725,974 
          Vice President — Trading                            
          (1)Dollar amounts represent the compensation expense recognized in 2006 with respect to outstanding phantom unit grants under our LTIP, whether or not granted during 2006. See Note 10 to our Consolidated Financial


          108

          Statements for a discussion of the assumptions made in determining these amounts. While substantially all of the performance thresholds for earning the phantom units represented by these amounts had been met as of December 29, 2006, none of the amounts included in this column were vested as of such date as they contain ongoing service requirements and, subject to meeting those requirements, will vest in various increments in 2007, 2008, 2009 and 2010.
          (2)Our general partner matches 100% of employees’ contributions to its 401(k) plan in cash, subject to certain limitations in the plan. All Other Compensation for Messrs. Armstrong, Pefanis, Kramer, Coiner and vonBerg includes $15,000 in such contributions. The remaining amount represents premium payments on behalf of the Named Executive Officer for group term life insurance.
          (3)Includes quarterly bonuses aggregating $2,040,100 and an annual bonus of $1,350,000. The annual bonus is payable 60% at the time of award and 20% in each of the two succeeding years.
          (4)Includes quarterly bonuses aggregating $1,834,700 and an annual bonus of $1,100,000. The annual bonus is payable 60% at the time of award and 20% in each of the two succeeding years.
          Grants of Plan-Based Awards Table
          This table has been omitted because no plan-based awards were made in 2006. See “— Compensation Discussion and Analysis.”
          Narrative Disclosure to us.Summary Compensation Table and Grants of Plan-Based Awards Table
          A discussion of 2006 salaries and bonuses is included in “— Compensation Discussion and Analysis.” The following is a discussion of other material factors necessary to an understanding of the information disclosed in the Summary Compensation Table.
          2006 Salary — As discussed in our CD&A, we do not make systematic annual adjustments to the salaries of 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 Item 13. "Certain Relationships and Related Transactions—Transactions with Related Parties."



          		Annual Compensation
          		Long-Term
          Compensation
          Name and Principal Position
          		Year
          		Salary
          		Bonus
          		Other
          Compensation
          		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

          $
          $
          $
          —
          —
          —

          $
          $
          $
          —
          —
          —
          (1)
          Salary amounts shownOfficers. Accordingly, no salary adjustments were made 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 Item 13. "Certain Relationships and Related Transactions—Transactions with Related Parties."

          (2)
          Prior to the transfer of a majorityany of our general partner interestexecutive officers 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
          2006.

            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 primaryinitial three-year term of Mr. Armstrong'sArmstrong’s employment agreement runs for three years fromcommenced on June 30, 2001. The term will be2001, and is automatically extended byfor one year on June 30 of each anniversary ofyear (such that the initial date (June 30, 2001)term is reset to three years) unless Mr. Armstrong receives notice from the Chairmanchairman of the Compensation Committeecompensation committee that the Boardboard of Directorsdirectors 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)exceptions, including, but not limited to, requirement of law or prior disclosure by a third party) any confidential information obtained by him while employed under the agreement. The agreement providesprovided for a current base salary of $330,000 per year, subject to annual review. IfIn 2005, Mr. Armstrong's employment is terminated without cause, he will be entitledArmstrong’s annual salary was increased to receive an amount equal to his annual base salary plus his highest annual bonus, multiplied by the lesser$375,000. See “— Compensation Discussion and Analysis” for a discussion 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 basehow salary and bonus. Underbonus are used to achieve compensation objectives. See “— Potential Payments Upon Termination orChange-In-Control” for a discussion of the provisions in Mr. Armstrong'sArmstrong’s employment agreement a "changerelated to termination, change of control" is defined to include (i) the acquisition by an entity or group (other than Plains Resourcescontrol 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 sumrelated 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.

          obligations.

          Mr. Pefanis is employed as President and Chief Operating Officer. The primaryinitial three-year term of Mr. Pefanis'Pefanis’ employment agreement runs for three years fromcommenced on June 30, 2001. The term will be2001, and is automatically extended byfor one year on June 30 of each anniversary ofyear (such that the initial date (June 30, 2001)term is reset to three years) unless Mr. Pefanis receives notice from the Chairmanchairman of the Boardboard of Directorsdirectors that the Boardboard 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 information obtained by him while employed under the agreement. The agreement providesprovided for a current base salary of $235,000 per year, subject to annual review. TheIn 2005, Mr. Pefanis’ annual salary was increased to $300,000. See “— Compensation Discussion and Analysis” for a discussion of how salary and bonus are used to achieve compensation objectives. See “— Potential Payments Upon Termination orChange-In-Control” for a discussion of the provisions in Mr. Pefanis'Pefanis’ employment agreement with respectrelated to termination, change inof control and related payment obligations are substantially similar to the parallel provisionsobligations.


          109

          In connection with Mr. vonBerg’s employment in Mr. Armstrong's agreement.


          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 ofJanuary 2002, our general partner and its affiliates who perform servicesMr. vonBerg entered into a letter agreement setting forth the terms of his employment. Such letter agreement provided for us. The LTIP consistsMr. vonBerg’s position to be Director, Trading at a base salary of two components,$200,000 per year and his participation in 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. The plan is administeredquarterly bonus pool based on gross margin generated by the employee’s business unit, discretionary annual bonus pool and employee benefits provided to all employees generally. See “— Compensation CommitteeDiscussion and Analysis” for a discussion of our general partner's boardhow salary and bonus are used to achieve compensation objectives. The letter agreement expired in accordance with its terms in January 2007. Mr. vonBerg also entered into an ancillary agreement which provides that for a period of directors. Our general partner's board of directorsone year following his termination, he will not disclose (subject to typical exceptions) any confidential information obtained by him while employed under the agreement and he will not, for one year after termination, engage in its discretion may terminate the LTIPcertain transactions with certain suppliers and customers.

          Outstanding Equity Awards at any timeFiscal Year-End
          The following table sets forth certain information 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 unitsoutstanding equity awards at December 31, 2006 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 recently vested or are expected to vest in the first half of 2004. As of February 17, 2004, giving effect to vested grants, grants of approximately 684,000 unvested phantom units remain outstanding to employees, officers and directors of our general partner. As discussed below, a substantial portion of these phantom units are expected to vest in May 2004. 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. 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, the Partnership 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). If we issue new common units upon vesting of the phantom units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units.

                  The phantom units (other than director grants) granted during the subordination period were subject to the basic restriction that vesting could take place only after and in proportion to any conversion of subordinated units into common units. Certain grants were subject to additional vesting criteria, primarily related to the Partnership's performance. In November 2003, 25% of the outstanding subordinated units converted on a one-for-one basis into common units and the remainder of our subordinated units converted into common units in February 2004. As a result, approximately 35,000 phantom units vested in November 2003, approximately 326,000 phantom units vested in February 2004, and we anticipate that another approximately 473,000 additional phantom units will vest in May 2004, subject to the satisfication of service period requirements.

                  We paid cash in lieu of issuing units for approximately 111,000 of the phantom units that have vested to date. We have issued approximately 156,000 new common units (after netting for taxes) in satisfaction of vesting. We anticipate paying cash for approximately 201,000 of the phantom units expected to vest in May, as well as approximately 181,000 new common units (after netting for taxes) in connection with such vesting. As a result of the vesting of these awards, we recognized an expense of approximately $7.4 million as of September 30, 2003 and an expense of approximately $28.8 million as



          of December 31, 2003. Based on a probability assessment combined with an amortization of service period, we anticipate recognizing an expense of $1.9 million and $0.6 million in the first and second quarters of 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 with the consummation of the General Partner Transition. 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 and second vestings took place on June 8, 2002 and June 8, 2003. See "—Compensation of Directors."

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

          Outstanding Equity Awards at Fiscal Year-End
                                               
            Option Awards  Stock Awards 
                                 Equity
          		  Equity
          		 
                                 Incentive
          		  Incentive
          		 
                  Equity
          		              Plan
          		  Plan
          		 
                  Incentive
          		              Awards:
          		  Awards:
          		 
                  Plan
          		           Market
          		  Number of
          		  Market or
          		 
                  Awards:
          		        Number
          		  Value
          		  Unearned
          		  Payout Value
          		 
            Number of
          		  Number of
          		  Number of
          		        of Shares
          		  of Shares
          		  Shares,
          		  of Unearned
          		 
            Securities
          		  Securities
          		  Securities
          		        or Units
          		  or Units
          		  Units or
          		  Shares, Units
          		 
            Underlying
          		  Underlying
          		  Underlying
          		        of Stock
          		  of Stock
          		  Other
          		  or Other
          		 
            Unexercised
          		  Unexercised
          		  Unexercised
          		  Option
          		  Option
          		  that Have
          		  that Have
          		  Rights that
          		  Rights That
          		 
            Options (#)
          		  Options (#)
          		  Unearned
          		  Exercise
          		  Expiration
          		  Not
          		  Not
          		  Have Not
          		  Have Not
          		 
          Name
          		 Exercisable
          		  Unexercisable
          		  Options (#)
          		  Price ($)
          		  Date
          		  Vested (#)
          		  Vested ($)
          		  Vested (#)
          		  Vested ($)(1)
          		 
           (a)
          		 (b)  (c)  (d)  (e)  (f)  (g)  (h)  (i)  (j) 
           
          Greg L. Armstrong  37,500(2)  —   —  $11.55   06/07/2011   —   —   —   — 
             —   —   —   —   —   —   —   300,000(3)  15,360,000 
          Harry N. Pefanis  27,500(2)  —   —  $11.55   06/07/2011   —   —   —   — 
             —   —   —   —   —   —   —   200,000(3)  10,240,000 
          Phillip D. Kramer  22,500(2)  —   —  $11.55   06/07/2011   —   —   —   — 
             —   —   —   —   —   —   —   100,000(4)  5,120,000 
          George R. Coiner  21,250(2)  —   —  $11.55   06/07/2011   —   —   —   — 
             —   —   —   —   —   —   —   80,000(4)  4,096,000 
             —   —   —   —   —   —   —   70,000(5)  3,584,000 
          John P. vonBerg  —   —   —   —   —   —   —   50,000(4)  2,560,000 
             —   —   —   —   —   —   —   40,000(5)  2,048,000 
          (1)Market value of stock reported in this column is calculated by multiplying the closing market price ($51.20) of the Partnership’s common units at December 29, 2006 (the last trading day of the fiscal year) by the number of units. Approximately one third of the value reflected in this column is also reflected in the Summary Compensation Table.
          (2)The units underlying the options were contributed to our general partner by its owners. We have no obligation to reimburse our general partners for the units upon exercise of the options. Mr. Armstrong vested in 18,750 options on April 22, 2002 and 18,750 options on July 21, 2004. Mr. Pefanis vested in 13,750 options on each of the same dates. Mr. Kramer vested in 11,250 options on each of the same dates. Mr. Coiner vested in 10,625 options on each of the same dates.
          (3)These phantom units will vest 30%, 30% and 40% solely upon achievement by the Partnership of annualized distributions of $2.60, $2.80 and $3.00 per unit and continued employment through May 2007, May 2009 and May 2010, respectively. Any phantom units that have not vested (and all associated DERs) as of the May 2012 distribution date will be forfeited. DERs associated with these phantom units become payable 30%, 15%, 15%,


          110

           
          		  
          		 November 2003
          Vesting
          		 February 2004
          Vesting
          		 May-04
          Vesting (anticipated)
          		 Remaining
          Unvested
          Grants(3)
          Name
          		 Total
          Units
           Units
          		 Value(1)
          		 Units
          		 Value(1)
          		 Units
          		 Value(2)
          		 Units
          		 Value(2)
          Greg L. Armstrong 70,000 —  — 17,500 $551,250 17,500 $568,050 35,000 $1,136,100
          Harry N. Pefanis 70,000 15,000 $452,400 47,500 $1,511,550 2,500 $81,150 5,000 $162,300
          Phillip D. Kramer 50,000 —  — 12,500 $393,750 12,500 $405,750 25,000 $811,500
          George R. Coiner 67,500 7,500 $226,200 31,875 $1,028,869 9,375 $304,313 18,750 $608,625
          W. David Duckett — —  — —  — —  — —  —

          (1)
          As

          20% and 20% upon the earlier to occur of annualized distributions of $2.60 or May 2007, $2.70 or May 2008, $2.80 or May 2009, $2.90 or May 2010, and $3.00 or May 2010, respectively.
          (4)These phantom units will vest 40%, 30% and 30% upon achievement by the Partnership of annualized distributions of $2.60, $2.80 and $3.00 per unit and continued employment through May 2007, May 2009 and May 2010, respectively. Any phantom units that have not previously vested will fully vest on the May 2011 distribution date, subject to continued employment through such date. DERs associated with these phantom units become payable 40%, 15%, 15%, 15% and 15% upon the earlier to occur of annualized distributions of $2.60 or May 2007, $2.70 or May 2008, $2.80 or May 2009, $2.90 or May 2010, and $3.00 or May 2010, respectively.
          (5)These phantom units will vest in equal one-third increments solely upon achievement by the Partnership of annualized distributions of $2.90, $3.00 and $3.10 per unit and continued employment through May 2008, May 2009 and May 2010, respectively. DERs associated with these phantom units vest and become payable in equal one-third increments solely upon the payment of annualized distributions of $2.90, $3.00, and $3.10, respectively. Any phantom units that have not vested (and all associated DERs) as of the May 2012 distribution date will be forfeited.
          Option Exercises and Stock Vested Table
          This table has been omitted because there were no exercises of vesting date.options by or vestings of LTIPs for the Named Executive Officers in 2006.
          Pension Benefits
          The Partnership sponsors a 401(k) plan that is available to all U.S. employees, but does not maintain a pension or defined benefit program.
          Nonqualified Deferred Compensation and Other Nonqualified Deferred Compensation Plans
          The Partnership does not have a nonqualified deferred compensation plan or program for its officers or employees.



          (2)
          Calculated111

          Potential Payments upon Termination orChange-in-Control
          The following table sets forth potential amounts payable to our current Named Executive Officers upon termination of employment under various circumstances, and as if vested and delivered, at a market value of $32.46 at the market close,terminated on December 31, 2003.29, 2006.
          Potential Payments upon Termination orChange-in-Control
                               
            By
          		  By
          		  By Company
          		  By Executive
          		  In Connection
          		 
            Reason of
          		  Reason of
          		  without
          		  with
          		  with a Change
          		 
            Death
          		  Disability
          		  Cause
          		  Good Reason
          		  in Control
          		 
          Termination:
          		 ($)  ($)  ($)  ($)  ($) 
           
                               
          Greg L. Armstrong
          		                    
          Salary and Bonus  6,750,000(1)  6,750,000(1)  6,750,000(1)  6,750,000(1)  10,125,000(2)
          Equity Compensation  15,360,000(3)  15,360,000(3)  15,360,000(2)(4)  15,360,000(2)  15,360,000(2)(5)
          Health Benefits  N/A   39,736(6)  39,736(6)  39,736(6)  39,736(6)
          TaxGross-up
          		  N/A   N/A   N/A   N/A   2,371,479(7)
          Total  22,110,000   22,149,736   22,149,736   22,149,736   27,896,215 
          Harry N. Pefanis
          		                    
          Salary and Bonus  6,100,000(1)  6,100,000(1)  6,100,000(1)  6,100,000(1)  9,150,000(2)
          Equity Compensation  10,240,000(3)  10,240,000(3)  10,240,000(4)  10,240,000(2)  10,240,000(2)(5)
          Health Benefits  N/A   39,736(6)  39,736(6)  39,736(6)  39,736(6)
          TaxGross-up
          		  N/A   N/A   N/A   N/A   2,112,233(7)
          Total  16,340,000   16,379,736   16,379,736   16,379,736   21,541,969 
          Phillip D. Kramer
          		                    
          Equity Compensation  5,120,000(3)  5,120,000(3)  5,120,000(4)  N/A   5,120,000(5)
          George R. Coiner
          		                    
          Equity Compensation  7,680,000(3)  7,680,000(3)  6,485,299(4)  N/A   7,680,000(5)
          John P. vonBerg
          		                    
          Equity Compensation  4,608,000(3)  4,608,000(3)  3,925,299(4)  N/A   4,608,000(5)
          (1)The employment agreements between our general partner and Messrs. Armstrong and Pefanis provide that if (i) their employment with our general partner is terminated as a result of their death, (ii) they terminate their employment with our general partner (a) because of a disability (as defined below) or (b) for good reason (as defined below), or (iii) our general partner terminates their employment without cause (as defined below), they are entitled to a lump-sum amount equal to the product of (1) the sum of their (a) highest annual base salary paid prior to their date of termination and (b) highest annual bonus paid or payable for any of the three years prior to the date of termination, and (2) the lesser of (i) two or (ii) the number of days remaining in the term of their employment agreement divided by 360. The amount provided in the table assumes for each executive a termination date of December 29, 2006, and also assumes a highest annual base salary of $375,000 and highest annual bonus of $3,000,000 for Mr. Armstrong, and a highest annual base salary of $300,000 and highest annual bonus of $2,750,000 for Mr. Pefanis.
          The employment agreements between our general partner and Messrs. Armstrong and Pefanis define “disability” as the impairment of health to an extent that makes the continued performance of their duties hazardous to physical or mental health or life.
          The employment agreements between our general partner and Messrs. Armstrong and Pefanis define “cause” as (i) willfully engaging in gross misconduct, or (ii) conviction of a felony involving moral turpitude. Notwithstanding, no act, or failure to act, on their part is “willful” unless done, or omitted to be done, not in good faith and without reasonable belief that such act or omission was in the best interest of our general partner or otherwise likely to result in no material injury to our general partner. However, neither Mr. Armstrong or Mr. Pefanis will be deemed to have been terminated for cause unless and until there is delivered to them a copy of a resolution of the board of directors of our general partner at a meeting held for that purpose (after


          112

          reasonable notice and an opportunity to be heard), finding that Mr. Armstrong or Mr. Pefanis, as applicable, was guilty of the conduct described above, and specifying the basis for that finding.
          The employment agreements between our general partner and Messrs. Armstrong and Pefanis define “good reason” as the occurrence of any of the following circumstances: (i) removal by our general partner from, or failure to re-elect them to, the positions to which Messrs. Armstrong and Pefanis were appointed pursuant to their respective employment agreements, except in connection with their termination for cause (as defined above); (ii) (a) a reduction in their rate of base salary (other than in connection withacross-the-board salary reductions for all executive officers of our general partner, unless such reduction reduces their base salary to less than 85% of their current base salary, (b) a material reduction in their fringe benefits, or (c) any other material failure by our general partner to comply with its obligations under their employment agreements to pay their annual salary and bonus, reimburse their business expenses, provide for their participation in certain employee benefit plans and arrangements, furnish them with suitable office space and support staff, or allow them no less than 15 business days of paid vacation annually; or (iii) the failure of our general partner to obtain the express assumption of the employment agreements by a successor entity (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the businessand/or assets of our general partner.
          (2)Pursuant to their employment agreements, if Messrs. Armstrong and Pefanis terminate their employment with our general partner within three (3) months of a change in control (as defined below), they are entitled to a lump-sum payment in an amount equal to the product of (i) three and (ii) the sum of (a) their highest annual base salary previously paid to them and (b) their highest annual bonus paid or payable for any of the three years prior to the date of such termination. The amount provided in the table assumes a change in control and termination date of December 29, 2006, and also assumes a highest annual base salary of $375,000 and highest annual bonus of $3,000,000 for Mr. Armstrong, and a highest annual base salary of $300,000 and highest annual bonus of $2,750,000 for Mr. Pefanis.
          For this purpose a “change in control” means (i) the acquisition by an entity or group (other than Plains Resources Inc. or a wholly owned subsidiary thereof) of 50% or more of the membership interest of our general partner or (ii) the existing owners of the membership interests of our general partner ceasing to own more than 50% of the membership interests of our general partner.
          In August 2005, Vulcan Energy increased its interest in our general partner from approximately 44% to approximately 54%. The consummation of the transaction constituted a change of control under the employment agreements with Messrs. Armstrong and Pefanis. However, Messrs. Armstrong and Pefanis entered into agreements with our general partner waiving their rights to payments under their employment agreements in connection with the change of control, contingent on the execution and performance by Vulcan Energy of a voting agreement with GP LLC that restricts certain of Vulcan’s voting rights. Upon a breach, termination, or notice of termination of the voting agreement by Vulcan Energy these waivers will automatically terminate and the executive officer will be paid a lump sum as if he had terminated his employment for good reason. Upon any termination by the Company without cause or by the executive for good reason, such executive officer would also vest in all outstanding phantom units under our LTIPs.
          (3)The letters evidencing the 2005 phantom unit grants to the Named Executive Officers provide that in the event of their death or disability (as defined below), all of their then outstanding phantom units and associated DERs will be deemed 100% nonforfeitable, and such phantom units and associated DERs will vest (i.e., the phantom units will become payable in the form of one common unit and the associated DERs will become payable in a cash lump-sum payment) as provided in Footnote 3 to the “Outstanding Equity Awards at Fiscal Year-End” table. For this purpose “disability” means a physical or mental disability that impairs the ability to perform duties for a period of eighteen (18) months or that the general partner otherwise determines constitutes a disability.
          The dollar value amount provided assumes the death or disability occurred on December 29, 2006. As a result, all phantom units and the associated DERs of the Named Executive Officers would have become nonforfeitable effective as of December 29, 2006, and vested at the time(s) described in Footnote 3 to the “Outstanding Equity Awards at Fiscal Year-End” table. The dollar value given is based on the market value on December 29, 2006 ($51.20 per unit) without discount for vesting period.


          (3)
          113

          (4)Pursuant to the 2005 phantom unit grants to the Named Executive Officers, in the event their employment is terminated other than in connection with a change in control (as defined in Footnote 5, below) or by reason of death or disability (as defined in Footnote 3, above), all of the DERs (regardless of vesting) and phantom units then outstanding under their respective 2005 phantom unit grants would automatically be forfeited as of the date of termination; provided, however, that if our general partner terminated their employment other than for cause (as defined below), any unvested phantom units that had satisfied all of the vesting criteria as of the date of their termination but for the passage of time would be deemed nonforfeitable and would vest on the next following distribution date. The dollar value amount provided assumes that the Named Executive Officers were terminated without cause on December 29, 2006. As a result, all of the outstanding phantom units held by Messrs. Armstrong, Pefanis and Kramer would be deemed nonforfeitable and would vest on the February 2007 distribution date. All outstanding phantom units, except for 23,334 and 13,334 held by Messrs. Coiner and vonBerg, respectively, would be deemed nonforfeitable and would vest on the February 2007 distribution date. The dollar value given is based on the market value on December 29, 2006 of $51.20 per unit, without discount for vesting period.
          (5)The 2005 phantom unit grants to the Named Executive Officers provide that in the event of a change of status (as defined below), all of the then outstanding phantom units and tandem DERs will be deemed 100% nonforfeitable, and such phantom units will vest in full (i.e., become payable in the form of one common unit of our general partner for each phantom unit) upon the next distribution date. Assuming the change in status occurred on December 29, 2006, all outstanding phantom units and the associated DERs would have become nonforfeitable as of December 29, 2006, and such phantom units and tandem DERs would vest (i.e., become payable) on the February 2007 distribution date.
          The phrase “change in status” means, with respect to a Named Executive Officer, the occurrence, during the period beginning three months prior to and ending one year following a change of control (as defined below), of any of the following: (i) termination of employment by our general partner other than a termination for cause (as defined below); (ii) without consent, the removal from, or any failure to re-elect them to, the position(s) held by them (or substantially equivalent position(s)) immediately prior to the change in control; (iii) any reduction in their base salaries; or (iv) any material reduction in their fringe benefits.
          The phrase “change of control” means, and is deemed to have occurred upon the occurrence of, one or more of the following events; (i) GP LLC ceasing to be the general partner of our general partner; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Partnership or GP LLC to any personand/or its affiliates, other than to the Partnership or GP LLC, including any employee benefit plan thereof; (iii) the consolidation, reorganization, merger, or any other similar transaction involving (A) a person other than the Partnership or GP LLC and (B) the Partnership, GP LLC or both; (iv) the persons who own membership interests in GP LLC ceasing to beneficially own, directly or indirectly, more than 50% of the membership interests of GP LLC; or (v) any person, including any partnership, limited partnership, syndicate or other group deemed a “person” for purposes of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended, becoming the beneficial owner, directly or indirectly, of more than 49.9% of the membership interest in GP LLC. With respect to the lattermost event, the grant letter makes an exception for any existing member of GP LLC if the member signs a voting agreement such as that executed by Vulcan in August 2005 (such exception not applying to the November 2005 grants to Messrs. Coiner and vonBerg).
          The term “cause” means (i) the failure to perform a job function in accordance with standards described in writing, or (ii) the violation of our general partner’s Code of Business Conduct (unless waived in accordance with the terms thereof), in each case, with the specific failure or violation described in writing.
          (6)Pursuant to their employment agreements with our general partner, if Messrs. Armstrong or Pefanis are terminated other than (i) for cause (as defined in Footnote 1, above), (ii) by reason of death or (iii) by resignation (unless such resignation is due to a disability or for good reason (each as defined in Footnote 1, above)), then they are entitled to continue to participate, for a period which is the lesser of two years from the date of termination or the remaining term of the employment agreement, in such health and accident plans or arrangements as is made available by our general partner to its executive officers generally. The amounts provided in the table assume a termination date of December 29, 2006.


          114

          (7)Pursuant to their employment agreements, Messrs. Armstrong and Pefanis will be reimbursed for any excise tax due under Section 4999 of the Code as a result of compensation (parachute) payments made under their respective employment agreements. The range of values of this benefit assumes that Messrs. Armstrong and Pefanis were terminated in connection with a change in control effective as of December 29, 2006.
          Confidentiality, Non-compete and Non-solicitation Arrangements
          Pursuant to remaining grants, vesting is contingent uponhis employment agreement, Mr. Armstrong has agreed to maintain the Partnership achieving specified distribution thresholds. For such remaining grants, 50%confidentiality of company information for a period of five years after the units require an annualized per unit distributiontermination of $2.30his employment. Mr. Pefanis has agreed to a similar restriction for a period of one year following the termination of his employment. Mr. Coiner has agreed to maintain confidentiality and 50% require an annualized distribution levelnot to solicit customers or employees for a period of $2.50.

                  Unit Option Plan.    The Unit Option Plan under our LTIP currently permitstwo years after the granttermination of options covering common units. No grants have been made under the Unit Option Planhis employment. Mr. vonBerg has agreed to date. However, the Compensation Committee may, in the future, make grants under the planmaintain confidentiality and not 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 valuesolicit customers for a period of the units on the dateone year following termination 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.

          his employment.

          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. See Item 13. "Certain Relationships and Related Transactions—Transactions with Related Parties."

          Compensation of Directors

          The following table sets forth a summary of the compensation we paid to our non-employee directors in 2006:
          Director Compensation
                                       
                        Change in
          		       
                        Pension Value
          		       
                        and
          		       
                        Nonqualified
          		       
            Fees Earned
          		        Non-Equity
          		  Deferred
          		       
            or Paid in
          		  Stock
          		  Option
          		  Incentive Plan
          		  Compensation
          		  All Other
          		    
          Name
          		 Cash ($)
          		  Awards(1) ($)
          		  Awards ($)
          		  Compensation ($)
          		  Earnings
          		  Compensation ($)
          		  Total ($)
          		 
           (a)
          		 (b)  (c)  (d)  (e)  (f)  (g)  (h) 
           
          David N. Capobianco(2)  47,000   101,352   —   —   —   —   148,352 
          Everardo Goyanes  75,000   204,482   —   —   —   —   279,482 
          Gary R. Petersen(2)  45,000   101,352   —   —   —   —   146,352 
          Robert V. Sinnott  45,000   101,352   —   —   —   —   146,352 
          Arthur L. Smith  62,000   204,482   —   —   —   —   266,482 
          J. Taft Symonds  60,000   204,483   —   —   —   —   264,483 
          (1)During the last fiscal year, Messrs. Goyanes, Smith and Symonds were granted 2,500 units and Mr. Sinnott was granted 1,250 units, by virtue of the automatic re-grant of LTIP awards vested during the fiscal year. In addition, each member of the audit committee was awarded 5,000 units, which vest annually in 25% increments; these units are also subject to an automatic re-grant of the amount vested such that in each future fiscal year 1,250 units will simultaneous vest and be re-granted. Upon any vesting (other than the incremental audit committee awards), a cash equivalent payment is made to Vulcan Capital and an affiliate of EnCap as directed by Mr. Capobianco and Mr. Petersen, respectively. Each audit committee member (currently Messrs. Goyanes, Smith and Symonds) has 10,000 units outstanding. Because these awards are subject to an automatic re-grant of units upon any vesting, each audit committee member will always have outstanding an award of 10,000 units. Mr. Sinnott has 5,000 units outstanding, and because this award is subject to an automatic re-grant of units upon any vesting, Mr. Sinnott will always have outstanding an award of 5,000 units. The dollar value of these awards and other awards granted in prior years is presented in the table reflecting the dollar amount of compensation expense recognized by us for 2006. See Note 10 to our Consolidated Financial Statements for a discussion of the assumptions made in determining these amounts.
          (2)Mr. Capobianco assigns to Vulcan Capital any compensation attributable to his service as director. Mr. Petersen assigns to EnCap Energy Capital Fund III, L.P. any compensation attributable to his service as director.
          Each director of our general partner who is not an employee of our general partner is reimbursed for any travel, lodging and otherout-of-pocket expenses related to meeting attendance or otherwise related to service on the board (including, without limitation, reimbursement for continuing education expenses). Each non-employee director 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.$45,000. Mr. Armstrong is otherwise compensated for his services as an


          115

          employee and therefore receives no separate compensation for his services as a director. EachIn addition to the annual retainer, each committee chairman (other than the Audit Committee)chairman of the audit committee) receives $2,000 annually. The chairman of the Audit Committeeaudit committee receives $30,000 annually, and the other members of the Audit Committeeaudit committee receive $15,000 annually.annually, in each case, in addition to the annual retainer.
          Our non-employee directors receive LTIP awards or cash equivalent awards as part of their compensation. The LTIP awards vest annually in 25% increments over a four-year period and have an automatic re-grant feature such that as they vest, an equivalent amount is granted. The three non-employee directors who serve on our audit committee each received a grant of 10,000 units (vesting 2,500 units per year). 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.

                  In 2000, Messrs. Goyanes, Sinnott and Smith, as directors of our former general partner, received a grant of 5,000 phantom units (vesting 1,250 per year). Mr. Petersen and Mr. Capobianco each under our LTIP. The phantom units vested and were paid in 2001 in connection with the consummationhave assigned all director compensation to an affiliate of the General Partner Transition. Each non-employeeGP LLC member that appointed him as a director. Such affiliates receive an annual cash payment equivalent in value to the annual vesting of Mr. Sinnott’s award.

          All LTIP awards held by a director will vest in full upon the next vesting date after the death or disability (as determined in good faith by the board) of the director. For any “independent” directors (as defined in the GP LLC Agreement, and currently including Messrs. Goyanes, Smith and Symonds), the awards will also vest in full if such director (i) retires (no longer with full-time employment and no longer serving as an officer or director of our general partner received a grant of 5,000 phantom unitsany public company) or (ii) is removed from the Board or is not reelected to the Board, unless such removal or failure to reelect is for “good cause,” as defined in 2002. The units vest and are payable in 25% increments annually on each anniversary of June 8, 2001. The first and second vestings occurred on June 8, 2002 and June 8, 2003.

          the letter granting the units.

          Reimbursement of Expenses of ourOur 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. TheOur 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 General Partner Transition, 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 Item 13. "Certain“Certain Relationships and Related Transactions."Transactions, and Director Independence — Our General Partner.”


          116


          Item 12.

          Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
          Security Ownership of Certain Beneficial Owners and Management and Related Unitholders' Matters

          Beneficial Ownership of Limited Partner UnitsInterest

          Our common units and Class B common units outstanding represent 98% of our equity (limited partner interest). The 2% general partner interest is discussed separately below under the caption "Beneficial“— 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, andthe Named Executive Officers, of our general partner and by all directors and executive officers as a group as of February 17, 2004.20, 2007.
                   
               Percentage
          		 
               of
          		 
            Common
          		  Common
          		 
          Name of Beneficial Owner
          		 Units  Units(1) 
           
          Paul G. Allen  14,386,074(2)  13.1%
          Vulcan Energy Corporation  12,390,120(3)  11.3%
          Richard Kayne/Kayne Anderson Capital Advisors, L.P.   9,238,534(4)  8.4%
          Greg L. Armstrong  253,412(5)(6)(7)  (8)
          Harry N. Pefanis  146,567(6)(7)  (8)
          Phillip D. Kramer  98,370(6)(7)  (8)
          George R. Coiner  58,126(6)(7)  (8)
          John P. vonBerg  —(6)  (8)
          David N. Capobianco  —(9)  (8)
          Everardo Goyanes  11,200   (8)
          Gary R. Petersen  5,200(10)  (8)
          Robert V. Sinnott  16,250(11)  (8)
          Arthur L. Smith  13,350   (8)
          J. Taft Symonds  22,500   (8)
          All directors and executive officers as a group (15 persons)  811,120(7)(12)  (8)
          (1)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 “— Beneficial Ownership of General Partner Interest.” Giving effect to the indirect ownership by Vulcan Energy Corporation of a portion of our general partner, Mr. Allen may be deemed to beneficially own approximately 14% of our total equity. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Vulcan Energy Corporation or any of its affiliates.
          (2)Mr. Allen owns approximately 80.1% of the outstanding shares of common stock of Vulcan Energy Corporation. Mr. Allen also controls Vulcan Capital Private Equity I LLC (“Vulcan LLC”), which is the record holder of 1,995,954 common units. The address for Mr. Allen and Vulcan LLC 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 Vulcan Energy Corporation or any of its affiliates.
          (3)The address for Vulcan Energy Corporation is c/o Plains All American GP LLC, 333 Clay Street, Suite 1600, Houston, Texas 77002.
          (4)Richard A. Kayne is Chief Executive Officer and Director of Kayne Anderson Investment Management, Inc., which is the general partner of Kayne Anderson Capital Advisors, L.P. (“KACALP”). Various accounts (including KAFU Holdings, L.P., which owns a portion of our general partner) under the management or control of KACALP own 9,238,534 common units. Mr. Kayne may be deemed to beneficially own such units. In addition, Mr. Kayne directly owns or has sole voting and dispositive power over 270,365 common units. Mr. Kayne disclaims beneficial ownership of any of our partner interests other than units held by him or interests attributable to him by virtue of his interests in the accounts that own our partner interests. The address


          117

          Name of Beneficial Owner
          		 Common Units
          		 Percentage
          of Common
          Units
          		 Class B
          Common Units
          		 Percentage
          of Class B
          Units
          		 Percentage of
          Total Limited Partner Units(3)
          		 
          Plains Resources Inc.(1)(2) 11,087,912 19.4%1,307,190 100.0%21.20%
          Greg L. Armstrong 170,000(4)(5)(6) (7)— —  (7)
          Harry N. Pefanis 129,689(5)(6) (7)— —  (7)
          George R. Coiner 54,651(5)(6) (7)— —  (7)
          Phillip D. Kramer 61,285(5)(6) (7)— —  (7)
          W. David Duckett —(8)— — — — 
          Everardo Goyanes 6,200  (7)— —  (7)
          Gary R. Petersen(9) 1,550  (7)— —  (7)
          John T. Raymond(10) 114,971 — — —  (7)
          Robert V. Sinnott(11) 12,500  (7)— —  (7)
          Arthur L. Smith 12,500  (7)— —  (7)
          J. Taft Symonds 12,500  (7)— —  (7)
          All directors and executive officers as a group (16 persons) 625,635(5)(6)1.1%— — 1.2%

          (1)
          Plains Resources Inc. is the sole stockholder of Plains Holdings Inc., our former general partner. The record holder of the Class B Common Units is Plains Holdings Inc. The record holder of the common units is Plains Holdings II Inc., a wholly owned subsidiary of Plains Holdings Inc. The address of Plains Resources Inc., Plains Holdings Inc. and Plains Holdings II Inc. is 700 Milam, Suite 3100,

          for Mr. Kayne and Kayne Anderson Investment Management, Inc. is 1800 Avenue of the Stars, 2nd Floor, Los Angeles, California 90067.
          (5)Does not include approximately 173,444 common units owned by our general partner in connection with its Performance Option Plan. Mr. Armstrong disclaims any beneficial ownership of such units beyond his rights as a grantee under the plan. See Item 13. “Certain Relationships and Related Transactions, and Director Independence — General Partner’s Performance Option Plan.”
          (6)Does not include unvested phantom units granted under the 2005 LTIP, none of which will vest within 60 days of the date hereof. See “— Outstanding Equity Awards at Fiscal Year-End.”
          (7)Includes the following vested, unexercised options to purchase common units under the general partner’s Performance Option Plan. Mr. Armstrong: 37,500; Mr. Pefanis: 27,500; Mr. Kramer: 22,500; Mr. Coiner: 21,250; and all directors and executive officers as a group: 126,250.
          (8)Less than one percent.
          (9)The GP 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 as one of our directors by Vulcan Energy Corporation, of which he is Chairman of the Board. Mr. Capobianco owns an equity interest in Vulcan LLC and has the right to receive a performance-based fee based on the performance of the holdings of Vulcan LLC and Vulcan Energy Corporation. Mr. Capobianco disclaims any deemed beneficial ownership of our common units held by Vulcan Energy Corporation and Vulcan LLC or any of their affiliates beyond his pecuniary interest therein, if any. By virtue of its 54% ownership in the general partner, Vulcan Energy Corporation has the right at any time to cause the election of an additional director to the Board.
          (10)Pursuant to the GP LLC Agreement, Mr. Petersen has been designated one of our directors byE-Holdings III, L.P., an affiliate of EnCap Investments L.P., of which he is Senior Managing Director. Mr. Petersen disclaims any deemed beneficial ownership of the 618,896 common units held byE-Holdings III, L.P. andE-Holdings V, L.P. or other affiliates of EnCap Investments L.P. beyond his pecuniary interest. The address forE-Holdings III, L.P. andE-Holdings V, L.P. is 1100 Louisiana, Suite 3150, Houston, Texas 77002.
          (11)Pursuant to the GP 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 President. Mr. Sinnott disclaims any deemed beneficial ownership of any common 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.
          (12)As of February 23, 2007, no units were pledged by directors or Named Executive Officers. Certain of the directors and Named Executive Officers hold units in a marginable broker’s account, but none of the units were margined as of February 23, 2007.



          (2)
          Includes common units owned by Plains Resources, to be transferred to certain of our employees (former Plains Resources employees), subject to certain vesting conditions. See "Certain Relationships and Related Transactions—Transactions with Related Parties—Stock Option Replacement."

          (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 its indirect ownership of a portion of our general partner, Plains Resources Inc. owns approximately 21.7% of our total equity.

          (4)
          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. See Item 13. "Certain Relationships and Related Transactions—Transactions with Related Parties—Performance Option Plan." Mr. Armstrong disclaims any beneficial ownership of such units beyond his rights as a grantee under the plan.

          (5)
          Does not include unvested phantom units granted under the LTIP, none of which will vest within 60 days of the date hereof. A substantial number of phantom units are expected to vest in early May of 2004. See Item 11. "Executive Compensation—Long-Term Incentive Plan."


          (6)
          Includes the following vested, unexercised options to purchase common units. Mr. Armstrong: 18,750; Mr. Pefanis: 13,750; Mr. Coiner: 10,625; Mr. Kramer: 11,250; directors and officers as a group: 66,875. See Item 13. "Certain Relationships and Related Transactions—Transactions with Related Parties—Performance Option Plan."

          (7)
          Less than one percent.

          (8)
          In April 2004, we anticipate making a contingent purchase price payment relating to our CANPET acquisition. This payment may be made in cash or common units. Mr. Duckett, as an owner of CANPET, will receive 37.8% of any common units issued. See Note 7 of "Notes to Consolidated Financial Statements."

          (9)
          See note 1 to the table of Directors and Executive Officers under "—Directors and Executive Officers." 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.

          (10)
          Units include 97,171 units contributed to Sable Holdings, L.P. by John T. Raymond in exchange for a limited partner interest. Mr. Raymond has the right to reacquire such units. See note 1 to the table of Directors and Executive Officers under "—Directors and Executive Officers." Mr. Raymond disclaims any deemed beneficial ownership of any units (other than the 97,171 units mentioned above) held by Sable Holdings, L.P. or its affiliates or Plains Resources or its affiliates.

          (11)
          See note 1 to the table of Directors and Executive Officers under "—Directors and Executive Officers." 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.

          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 its 1% general partner, Plains All American GP LLC)LLC, its 1% general partner).

          Percentage
          Ownership of
          Name and Address of Owner
          		Percentage
          Ownership of
          Plains AAP, L.P.
          Plains Resources Inc.(1)
          700 Milam, Suite 3100
          Houston, TX 77002          		 44.000Plains AAP
          Paul G. Allen(1)54.3%

          Sable Investments, L.P.(2)
          700 Milam,505 Fifth Avenue S, Suite 3100900
          Seattle, WA 98104
          Vulcan Energy Corporation(2)54.3%
          c/o Plains All American GP LLC
          333 Clay Street, Suite 1600
          Houston, TX 77002
           
          20.000
          KAFU Holdings, L.P.(3)20.3%

          KAFU Holdings, L.P.(3)
          1800 Avenue of the Stars, 2nd Floor
          Los Angeles, CA 90067
           
          16.418
          E-Holdings III, L.P.(4)
          		9.0%

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

          9.000
          %

          Table continued on following page.


              


          E-Holdings V, L.P.(4)
          		2.1%
          1100 Louisiana, Suite 3150
          Houston, TX 77002
          PAA Management, L.P.(5)
          		4.9%
          333 Clay Street, #1600Suite 1600
          Houston, TX 77002
           
          4.000
          Wachovia Investors, Inc. 4.2%

          Wachovia Investors, Inc.
          301 South College Street, 12th Floor
          Charlotte, NC 28288
           
          3.382
          Mark E. Strome2.6%

          Mark E. Strome
          100 Wilshire Blvd., Suite 1500
          Santa Monica, CA 90401
           
          2.134
          Strome MLP Fund, L.P. 1.3%

          Strome Hedgecap Fund, L.P.
          100 Wilshire Blvd., Suite 1500
          Santa Monica, CA 90401
           
          1.066
          Lynx Holdings I, LLC1.2%
          15209 Westheimer, Suite 110
          Houston, TX 77082
          (1)
          Plains Resources Inc. is the sole stockholder of Plains Holdings Inc., which owns 44% of the equity of our general partner. 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. See Note 1 to the Directors and Executive Officers table under "—Directors and Executive Officers." The agreement is limited to such designations and the obligation to vote in favor of such designee.
          (1)Mr. Allen owns approximately 80.1% of the outstanding shares of common stock of Vulcan Energy Corporation. Vulcan Energy GP Holdings Inc., a subsidiary of Vulcan Energy Corporation, owns 54.3% of the equity of our general partner. Vulcan Energy Corporation has pledged all of its equity interest in Vulcan Energy GP Holdings Inc. as security for its obligations under the Second Amended and Restated Credit Agreement dated as of August 12, 2005 among Vulcan Energy Corporation, Bank of America, N.A. and the lenders party thereto (the “VEC Credit Agreement”). A default by Vulcan Energy Corporation under the VEC Credit Agreement could result in an indirect change in control of our general partner. Mr. Allen disclaims any deemed beneficial ownership, beyond his pecuniary interest, in any of our partner interests held by Vulcan Energy Corporation or any of its affiliates.
          (2)Mr. Capobianco disclaims any deemed beneficial ownership of the interests held by Vulcan Energy Corporation and its affiliates beyond his pecuniary interest therein, if any.
          (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.



          (2)
          John T. Raymond has the right to acquire a 1% interest in our general partner from Sable Investments, L.P. See Note 1 to the Directors and Executive Officers table under "—Directors and Executive Officers." Mr. Raymond disclaims any deemed beneficial ownership of the interests held by Plains Resources Inc. or Sable Investments, L.P. beyond such right.

          (3)
          See Note 1 to the Directors and Executive Officers table under "—Directors and Executive Officers." 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.

          (4)
          See Note 1 to the Directors and Executive Officers table under "—Directors and Executive Officers." 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 27%), Pefanis (approximately 15%), Kramer (approximately 10%) and Coiner (approximately 10%). Other than Mr. Armstrong, no directors own any interest in PAA Management, L.P. Directors and executive officers as a group own approximately 80% 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 November 20, 2003, Plains Resources (which owns all of the equity of Plains Holdings Inc.) announced that it had received a proposal from Vulcan Capital, along with James C. Flores and John T. Raymond, to acquire all of Plains Resources' outstanding stock for $14.25 per share in cash. Vulcan Capital is an investment vehicle for investor Paul G. Allen. Plains Resources also announced that its board of directors had formed a special committee to evaluate the proposal. On December 1, 2003, Vulcan and Messrs. Allen, Flores and Raymond filed a Schedule 13D with the Securities and Exchange Commission in connection with the proposed buyout. On February 19, 2004, Plains Resources announced that the special committee of its board of directors had recommended that the board of directors accept a revised offer of $16.75 per share. The February 19 announcement further indicated that Plains Resources' board of directors had accepted the special committee's recommendation,119



          approved a merger agreement and recommended that shareholders vote in favor of the transaction. Prior to the November announcement, we have received assurances from Mr. Flores, Mr. Raymond and representatives of Vulcan that if the proposed buyout is consummated, there is no intent to merge or otherwise combine the interests of Plains Holdings Inc. and Sable Investments, L.P. We cannot predict whether the stockholders of Plains Resources will approve the transaction or whether a competing transaction may be offered or considered.

          (4)Mr. Petersen disclaims any deemed beneficial ownership of the interests owned byE-Holdings III, L.P. andE-Holdings V, L.P. beyond his pecuniary interest.
          (5)PAA Management, L.P. is owned entirely by certain members of senior management, including Messrs. Armstrong (approximately 25%), Pefanis (approximately 14%), Kramer (approximately 9%), Coiner (approximately 9%) and vonBerg (approximately 4%). Other than Mr. Armstrong, no directors own any interest in PAA Management, L.P. Directors and executive officers as a group own approximately 76% 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.
          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 956,588(1) N/A(2) (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)$17.30(7) (8)
          *
          As
          The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2003

          (1)
          Our general partner has adopted and maintains2006. For a Long Term Incentive Plan for our officers, employees and directors. As originally instituted by our former general partner prior to our IPO, the LTIP contemplated awards of up to 975,000 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. In November 2003, we issued 18,412 units in satisfaction of vesting under the LTIP. The number of units (956,588) presented in column (a) subtracts the units issued in November and 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 February of 2004 were satisfied without the issuance of units. These phantom units were settled in cash or withheld for taxes. See Item 11. "Executive Compensation—Long-Term Incentive Plan." Any units not issued upon vesting can become "available for future issuance" under column (c).

          (2)
          Phantom unit awards under the LTIP vest without payment by recipients. See Item 11. "Executive Compensation—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." After giving effect to the vesting of phantom units in February 2004 and the anticipated vesting in May of 2004, we estimate that there will be approximately 211,000 phantom units outstanding and approximately 427,000 units available for future issuance (excluding phantom units outstanding). See Item 11. "Executive Compensation—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, alldescription of these awards must be satisfied 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 450,000 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.

          (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 andplans, see Item 13. "Certain“Certain Relationships and Related Parties—Performance Option Plan."

          (7)
          The current strike price for all outstanding options under the Performance Option Plan is $17.30 per unit. The strike price decreases as distributions are paid. Future grants may include different pricing elements. See Item 13. "Certain RelationshipsTransactions, and Related Parties—Performance Option Plan."Director Independence — Equity-Based Long-Term Incentive Plans.”
                       
            Number of Units to
          		     Number of Units
          		 
            be Issued upon
          		  Weighted Average
          		  Remaining Available
          		 
            Exercise/Vesting of
          		  Exercise Price of
          		  for Future Issuance
          		 
            Outstanding Options,
          		  Outstanding Options,
          		  under Equity
          		 
          Plan Category
          		 Warrants and Rights  Warrants and Rights  Compensation Plans 
            (a)  (b)  (c) 
           
          Equity compensation plans approved by unitholders:            
          1998 Long Term Incentive Plan  40,550(1)  N/A(2)  506,708(1)(3)
          2005 Long Term Incentive Plan  2,195,700(4)  N/A(2)  804,300(3)
          Equity compensation plans not approved by unitholders:            
          1998 Long Term Incentive Plan  —(1)(5)  N/A(2)  —(6)
          General Partner’s Performance Option Plan  —(7) $11.55(8)  —(7)
          PPX Successor LTIP  —   N/A   999,809(9)
          (1)As originally instituted by our former general partner prior to our initial public offering, the 1998 LTIP contemplated the 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 1998 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 December 31, 2006, we have issued approximately 427,742 common units in satisfaction of vesting under the 1998 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 have vested were satisfied without the issuance of units. These phantom units were settled in cash or withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c).
          (2)Phantom unit awards under the 1998 LTIP and 2005 LTIP vest without payment by recipients.
          (3)In accordance with Item 201(d) ofRegulation S-K, column (c) excludes the securities disclosed in column (a). However, as discussed in footnotes (1) and (4), any phantom units represented in column (a) that are not satisfied by the issuance of units become “available for future issuance.”
          (4)The 2005 Long Term Incentive Plan was approved by our unitholders in January 2005. The 2005 LTIP contemplates the issuance or delivery of up to 3,000,000 units to satisfy awards under the plan. The number of units presented in column (a) assumes that all outstanding grants will be satisfied by the issuance of new units upon vesting. In fact, some portion of the phantom units may be settled in cash and some portion will be withheld for taxes. Any units not issued upon vesting will become “available for future issuance” under column (c).



          (8)
          120

          (5)Although awards for units may from time to time be outstanding under the portion of the 1998 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.”
          (6)Awards for up to 387,032 phantom units may be granted under the portion of the 1998 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.
          (7)Our general partner has adopted a Performance Option Plan for officers and key employees pursuant to which optionees have the right to purchase units from the general partner. The 450,000 units that were originally authorized to be sold under the plan were contributed to the general partner by certain of its owners in connection with the transfer of a majority of our general partner interest in 2001 without economic cost to the Partnership. Thus, there will be no units “issued upon exercise/vesting of outstanding options.” Options for approximately 161,500 units are currently outstanding. All are vested, and no units remain available for future grant. See Item 13. “Certain Relationships and Related Transactions, and Director Independence — General Partner’s Performance Option Plan.”
          (8)As of December 31, 2006, the strike price for all outstanding options under the general partner’s Performance Option Plan was approximately $11.55 per unit. The strike price decreases as distributions are paid. See Item 13. “Certain Relationships and Related Transactions, and Director Independence — General Partner’s Performance Option Plan.”
          (9)In connection with the Pacific merger, under applicable stock exchange rules, we carried over the available units under the Pacific LTIP (applying the conversion ratio of 0.77 PAA units for each Pacific unit). In that regard, we have adopted the Plains All American PPX Successor Long-Term Incentive Plan (the “PPX Successor LTIP”). Potential awards under such plan include options and phantom units (with or without tandem DERs). The provisions of such plan are substantially the same as the 2005 LTIP, except that awards under the PPX Successor LTIP may only be made to employees who were working for Pacific at the time of the merger or to employees hired after the date of the Pacific acquisition.
          Item 13.Certain Relationships and Related Transactions, and Director Independence
          For a discussion of director independence, see Item 10 “Directors and Executive Officers of Our 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 Item 11. "Executive Compensation—Long-Term Incentive Plan" and Item 13. "Certain Relationships and Related Transactions—Transactions with Related Parties—Performance Option Plan."

          Item 13.Corporate Governance.”

          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.

          Total costs reimbursed by us to our general partner for the year ended December 31, 2006 were approximately $204.6 million.

          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 $0.675 ($2.70 annualized) per unit. In connection with the Pacific merger, our general partner agreed to a temporary reduction in the amount of incentive distribution right otherwise payable to it. The aggregate reduction will be $65 million over a five-year period, with a reduction of $20 million, $15 million, $15 million, $10 million and $5 million in years one through five, respectively. The first reduction was made in connection with the distribution paid on February 14, 2007.


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          The following table illustrates the allocation of aggregate distributions at differentper-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 $108,000 $2,204 $110,204 2.0%
          $2.00 $120,000 $4,510 $124,510 3.6%
          $2.20 $132,000 $8,510 $140,510 6.1%
          $2.40 $144,000 $12,510 $156,510 8.0%
          $2.60 $156,000 $16,510 $172,510 9.6%
          $2.80 $168,000 $24,510 $192,510 12.7%
          $3.00 $180,000 $36,510 $216,510 16.9%
          (1)
          In thousands.

          (2)
          Assumes 60,000,000 units outstanding. Actual number of units outstanding as of levels, excluding the date hereof are 58,469,828. An increase in the numbereffect 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

            reductions:

                           
                     GP Percentage
          		 
          Annual Distribution
          		 Distribution to
          		  Distribution
          		  Total
          		  of Total
          		 
          per Unit
          		 Unitholders(1)(2)  to GP(1)(2)(3)  Distribution(1)  Distribution 
           
          $1.80 $198,000  $4,041  $202,041   2.0%
          $1.98 $217,800  $7,535  $225,335   3.3%
          $2.70 $297,000  $33,935  $330,935   10.3%
          $3.20 $352,000  $88,935  $440,935   20.2%
          $3.50 $385,000  $121,935  $506,935   24.1%
          $3.75 $412,500  $149,435  $561,935   26.6%
          $4.00 $440,000  $176,935  $616,935   28.7%
          (1)In thousands.
          (2)Assumes 110,000,000 units outstanding. Actual number of units outstanding as of December 31, 2006 was 109,405,178. 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.
          General

                  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.

                  Plains Resources currently owns an effective 44% of our general partner interest, as well as approximately 21.2% of our outstanding limited partner units. Mr. John Raymond, one of our directors, is President and Chief Executive Officer of Plains Resources. Mr. Raymond was designated as a member of our board by Sable Investments, L.P., which is controlled by Mr. James Flores. Mr. Flores is the Executive Chairman of Plains Resources. We have ongoing relationships with Plains Resources. These relationships include but are not limited to:

            •
            a separation agreement entered into in connection with the General Partner Transition pursuant to which (i) Plains Resources has indemnified us for (a) claims relating to securities laws or regulations in connection with the upstream or midstream businesses, based on alleged acts or omissions occurring on or prior to June 8, 2001, or (b) claims related to the upstream business, whenever arising, and (ii) we have indemnified Plains Resources for claims related to the midstream business, whenever arising. Plains Resources also has agreed to indemnify and maintain liability insurance for the individuals who were, on or before June 8, 2001, directors or officers of Plains Resources or our former general partner.

            •
            a Pension and Employee Benefits Assumption and Transition Services Agreement that provided for the transfer to our general partner of the employees of our former general partner and certain headquarters employees of Plains Resources.

            •
            an Omnibus Agreement that provides for the resolution of certain conflicts arising from the fact that we and Plains Resources conduct related businesses, including certain non-compete obligations of Plains Resources.

              •
              a Marketing Agreement with Plains Resources that provides for the marketing of Plains Resources' equity crude oil production (including its subsidiaries that conduct exploration and production activities.). Under the Marketing Agreement, we purchase for resale at market prices the majority of Plains Resources equity production for a fee of $0.20 per barrel. The fee is subject to adjustment every three years based on then-existing market conditions. For the year ended December 31, 2003, Plains Resources produced approximately 2,000 barrels per day that were subject to the Marketing Agreement. We paid approximately $25.7 million for such production and recognized segment profit of approximately $0.2 million under the terms of that agreement. In our opinion, these purchases were made at prevailing market prices. In November 2001, the agreement automatically extended for an additional three-year period. Because Plains Resources divested itself of most of its producing properties at the end of 2002, we do not expect material amounts of crude oil to be subject to this agreement. We are in the process of negotiating an amended agreement to reflect the separation of Plains Resources and one of its subsidiaries, discussed below. As currently in effect, the Marketing Agreement (as well as the Omnibus Agreement described above) will terminate upon a "change of control" of Plains Resources or our general partner. The recently announced buyout of Plains Resources stock would constitute a change of control; however, we received assurances prior to the initial announcement that neither Plains Resources nor the buyout group intend for the agreement (or the substance of the Omnibus Agreement) to terminate.

                    On December 18, 2002, Plains Resources completed a spin-off of one of its subsidiaries, Plains Exploration and Production ("PXP") to its shareholders. Mr. Raymond is President and Chief Operating Officer of PXP. 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. We are in the process of negotiating the terms of an amended agreement with PXP.

              Transaction Grant Agreements

                    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.

              Equity-Based Long-Term Incentive PlanPlans

            Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan (the “1998 LTIP”) and the Plains All American GP LLC 2005 Long-Term Incentive Plan (the “2005 LTIP” and, together with the 1998 LTIP, the “Plans”) for employees and directors of our general partner and its affiliates who perform services for us. TheAwards contemplated by the Plans include phantom units (referred to as restricted units in the 1998 LTIP), distribution equivalent rights (DERs) and unit options. As amended, the 1998 LTIP consists of two components, a restricted unit plan and a unit option plan. The LTIP currently permitsauthorizes the grant of restricted units and unit optionsawards covering an aggregate of 1,425,000 common units.units deliverable upon vesting or exercise (as applicable) of such awards. The plan is administered2005 LTIP authorizes the grant of awards covering an aggregate of 3,000,000 common units deliverable upon vesting or exercise (as applicable) of such awards. Our general partner’s board of directors has the right to alter or amend the Plans 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.
            Common units to be delivered upon the vesting of rights may be common units acquired by the Compensation Committee of our general partner's boardpartner in the open market or in private transactions, common units already owned by our general partner, or any combination of directors.

            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 new common units to satisfy delivery obligations under the grants. When we issue new common units upon vesting of grants, the total number of common units outstanding increases.

            Phantom Units.  A restrictedphantom unit is a "phantom" unit that entitles the grantee to receive, a common unit upon the vesting of the phantom unit. unit, a common unit (or cash equivalent, depending on the terms of the grant).
            As of February 17, 2004, aggregateDecember 31, 2006, giving effect to vested grants, grants of approximately 187,000 common units have been issued or purchased40,550 and delivered upon vesting and approximately 680,0002,195,700 unvested phantom units remain outstanding under the 1998 LTIP and 2005 LTIP, respectively, and approximately 893,740 and 804,300 remain available for future grant, respectively. In addition, the PPX Successor LTIP has available 999,809 units that were adopted from the Pacific LTIP. These units can be used only in awards to former Pacific employees or employees hired after the date of the Pacific acquisition. The compensation committee or board of directors may, in the future, make additional grants under the Plans to employees officers and directors containing such terms as the compensation committee or board of our general partner. See Item 11. "Executive Compensation—Long-Term Incentive Plan."directors shall determine, including DERs with respect to phantom units. DERs entitle the grantee to a cash payment, either while the award is outstanding or upon vesting, equal to any cash distributions paid on a unit while the award is outstanding.


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            The issuance of the common units upon vesting of phantom units 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.
            Unit Options.  Although the Plans currently permit the grant of options covering common units, no options have been granted under the Plans to date. However, the compensation committee or board of directors may, in the future, make grants under the plan to employees and directors containing such terms as the compensation committee or board of directors shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant.
            General Partner’s Performance Option Plan

            In connection with the General Partner Transition, the2001, certain 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 toPlan. As of December 31, 2006, 171,000 options remain outstanding under the plan, all of which options to purchase approximately 375,000are fully vested. No 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 278,000 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, and 25% of the options vested, in 2002. The options will vest in their entirety immediately upon a change in control (as defined in the grant agreements).remain available for future grant. The original purchaseexercise price underof the options was $22 per subordinated unit, declining over time inby an amount equal to 80% of each quarterly distribution per unit. As of February 17, 2004,December 31, 2006, the purchaseexercise price was $17.30approximately $11.55 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.

            Transactions with Related Persons
            Stock Option ReplacementVulcan Energy
            As of December 31, 2006, Vulcan Energy and its affiliates owned approximately 54% of our general partner interest, as well as approximately 11.3% of our outstanding limited partner units.
            Voting Agreement

            In connection with the General Partner Transition, certain membersAugust 2005, one of the management team that had been employed by Plains Resources, including Messrs. Armstrong, Pefanis and Kramer, were transferredowners of our general partner notified the remaining owners of its intent to sell its 19% interest in the general partner. The remaining owners elected to exercise their right of first refusal, such that the 19% interest was purchased pro rata by all remaining owners. As a result of the transaction, the interest of Vulcan Energy increased from 44% to approximately 54%. At the closing of the transaction, Vulcan Energy entered into a voting agreement that restricts its ability to unilaterally elect or remove our independent directors, and separately, our CEO and COO agreed, subject to certain ongoing conditions, to waive certainchange-of-control payment rights that would otherwise have been triggered by the increase in Vulcan Energy’s ownership interest. These ownership changes to our general partner had no material impact on us.
            Administrative Services Agreement
            On October 14, 2005, GP LLC and Vulcan Energy entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, GP LLC provides administrative services to Vulcan Energy for consideration of an annual fee, plus certain expenses. Effective October 1, 2006, the annual fee for providing these services was increased to $1.0 million. The Services Agreement extends through October 2008, at which time it will automatically renew for successive one-year periods unless either party provides written notice of its intention to terminate the Services Agreement. Pursuant to the agreement, Vulcan Energy has appointed certain employees of GP LLC as officers of Vulcan Energy for administrative efficiency. Under the Services Agreement, Vulcan Energy acknowledges that conflicts may arise between itself and GP LLC. If GP LLC believes that a specific service is in conflict with the best interest of GP LLC or its affiliates then GP LLC is entitled to suspend the provision of that service and such individuals held in-the-money but unvested stock options ina suspension will not constitute a breach of the Services Agreement. Vulcan Gas Storage LLC (discussed below) operates separately from Vulcan Energy, and services we provide to Vulcan Gas Storage LLC are not covered under the Services Agreement.


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            Predecessor Agreements
            In 2001, Plains Resources, Inc. transferred a portion of its indirect interest in our general partner to certain of the current owners. As successor in interest to Plains Resources, Vulcan Energy is party to certain agreements related to such transfer, including the following:
            • a separation agreement entered into in 2001 in connection with the transfer of interests in our general partner pursuant to which (i) Vulcan indemnifies us for (a) claims relating to securities laws or regulations in connection with the upstream or midstream businesses, based on alleged acts or omissions occurring on or prior to June 8, 2001, or (b) claims related to the upstream business, whenever arising, and (ii) we indemnify Vulcan for claims related to the midstream business, whenever arising. Vulcan also indemnifies, and maintains liability insurance (through June 8, 2007) for the individuals who were, on or before June 8, 2001, directors or officers of Plains Resources or our former general partner.
            • a Pension and Employee Benefits Assumption and Transition Services Agreement that provided for the transfer to our general partner of the employees of our former general partner and certain headquarters employees of Plains Resources.
            • an Omnibus Agreement that provides for the resolution of certain conflicts of interest, including certain non-compete obligations.
            Crude Oil Purchases
            Until August 12, 2005, Vulcan Energy owned 100% of Calumet Florida L.L.C. Calumet is now owned by Vulcan Resources Florida, Inc., the majority of which is owned by Paul G. Allen. We purchase crude oil from Calumet. We paid approximately $45.1 million to Calumet in 2006. Calumet may request from time to time that we provide fixed pricing or a range of pricing for a portion of its production. When we offer such an arrangement, we protect our position by placing hedges on equivalent amounts, and charge Calumet a fee of $0.20 per barrel. No such arrangements were in place during 2006.
            Other
            In addition to those relationships described above, we have engaged in other transactions with affiliates of Vulcan Energy. See “— Equity Offerings” and “— Investment in Natural Gas Storage Joint Venture.”
            Equity Offerings
            In December 2006, we sold 6,163,960 common units, approximately 10% and 10% of which were subjectsold to forfeiture becauseinvestment funds affiliated with KACALP and Encap Investments, L.P., respectively. In July and August 2006, we sold a total of the transfer of employment. Plains Resources, through its affiliates, agreed to substitute a contingent grant of subordinated units (or3,720,930 common units, after conversion)approximately 12.5% and 18.7% of which were sold to investment funds affiliated with KACALP and Vulcan Capital, respectively. In addition, in March and April 2006, we sold 3,504,672 common units, approximately 20% of which were sold to investment funds affiliated with KACALP. KAFU Holdings, L.P., which owns 20.3% of our general partner and has a value equalrepresentative on our board of directors, is managed by KACALP. Vulcan Capital, the investment arm of Paul G. Allen, and its subsidiaries own approximately 54% of our general partner interest and has a representative on our board of directors. Affiliates of EnCap own approximately 11.1% of our general partner and have a representative on our board of directors.
            In September 2005, we sold 4,500,000 units in a public offering at a unit price to the spread onpublic of $42.20. We received net proceeds of approximately $182.3 million, or $40.512 per unit after underwriters’ discounts and commissions. Concurrently with the unvested options,public offering, we sold 679,000 common units pursuant to our existing shelf registration statement to investment funds affiliated with distribution equivalent rights fromKACALP in a privately negotiated transaction for a purchase price of $40.512 per unit (equivalent to the datepublic offering price less underwriting discounts and commissions). On February 25, 2005, we issued 575,000 common units in a private placement to a subsidiary of grant.Vulcan Capital. The grant included 8,548, 4,602 and 9,742 unitssale price was $38.13 per unit, which represented a 2.8% discount 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 deliveryclosing price 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.on February 24, 2005.


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            Tank Car Lease and CANPET Energy Group Inc.

            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"“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. As of December 31, 2003, we determined that it was beyond a reasonable doubt that the performance standards were met and we recorded additional consideration of $24.3 million, (see Note 7—"Partners' Capital and Distributions" in the "Notes to the Consolidated Financial Statements"), resulting in aggregate consideration of approximately $73.9 million. 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 will receive a proportionate share of the proceeds from any contingent payment of purchase price for the CANPET assets.

              Tank Car Lease and CANPET

            CANPET. In connection with the CANPET asset acquisition, Plains Marketing Canada, L.P. assumed CANPET'sCANPET’s rights and obligations under a Master Railcar Leasing Agreement between CANPET and Pivotal Enterprises Corporation ("Pivotal"(“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%23.4% interest in Pivotal.

            OtherClass C Common Units
            In April 2004, we sold 3,245,700 unregistered Class C common units (the “Class C common units”) to a group of investors consisting 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 Item 12. “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 on 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 million. We used the net proceeds from the offering to repay indebtedness under our revolving credit facility incurred in connection with the Link acquisition. In January 2005, our common unitholders approved a change in the terms of the Class C common units such that they were immediately convertible into an equal number of common units at the option of the holders, and in February 2005, all of the Class C common units converted.
            Investment in Natural Gas Storage Joint Venture
            PAA/Vulcan, a limited liability company, was formed in the third quarter of 2005. We own 50% of PAA/Vulcan and the remaining 50% is owned by Vulcan Gas Storage LLC, a subsidiary of Vulcan Capital, the investment arm of Paul G. Allen. The Board of Directors of PAA/Vulcan consists of an equal number of our representatives and representatives of Vulcan Gas Storage, and is responsible for providing strategic direction and policy-making. We, as the managing member, are responsible for theday-to-day operations.
            In September 2005, PAA/Vulcan acquired ECI, an indirect subsidiary of Sempra Energy, for approximately $250 million. ECI develops and operates underground natural gas storage facilities. We and Vulcan Gas Storage LLC each made an initial cash investment of approximately $112.5 million, and Bluewater Natural Gas Holdings, LLC a subsidiary of PAA/Vulcan (“Bluewater”) entered into a $90 million credit facility contemporaneously with closing. Approximately $25.4 million was outstanding under this credit facility as of February 20, 2007. We currently have no direct or contingent obligations under the Bluewater credit facility.
            PAA/Vulcan is developing a natural gas storage facility through its wholly owned subsidiary, Pine Prairie Energy Center, LLC (“Pine Prairie”). Proper functioning of the Pine Prairie storage caverns will require a minimum operating inventory contained in the caverns at all times (referred to as “base gas”). During the first quarter of 2006, we arranged to provide the base gas for the storage facility to Pine Prairie at a price not to exceed $8.50 per million cubic feet. In conjunction with this arrangement, we executed hedges on the NYMEX for the relevant delivery periods of 2007, 2008 and 2009. We received a fee of approximately $1 million for our services to own and manage the hedge positions and to deliver the natural gas.
            We and Vulcan Gas Storage are both required to make capital contributions in equal proportions to fund equity requests associated with certain projects specified in the joint venture agreement. For certain other specified projects, Vulcan Gas Storage has the right, but not the obligation, to participate for up to 50% of such equity requests. In some cases, Vulcan Gas Storage’s obligation is subject to a maximum amount, beyond which Vulcan Gas Storage’s participation is optional. For any other capital expenditures, or capital expenditures with respect to


            125

                    An

            which Vulcan Gas Storage’s participation is optional, if Vulcan Gas Storage elects not to participate, we have the right to make additional capital contributions to fund 100% of the project until our interest in PAA/Vulcan equals 70%. Such contributions would increase our interest in PAA/Vulcan and dilute Vulcan Gas Storage’s interest. Once PAA’s ownership interest is 70% or more, Vulcan Gas Storage would have the right, but not the obligation, to make future capital contributions proportionate to its ownership interest at the time.
            In conjunction with formation of PAA/Vulcan and the acquisition of ECI, PAA and Paul G. Allen provided performance and financial guarantees to the seller with respect to PAA/Vulcan’s performance under the purchase agreement, as well as in support of continuing guarantees of the seller with respect to ECI’s obligations under certain gas storage and other contracts. PAA and Paul G. Allen would be required to perform under these guarantees only if ECI was unable to perform. In addition, we provided a guarantee under one contract with an indefinite life for which neither Vulcan Capital nor Paul G. Allen provided a guarantee. In exchange for the disproportionate guarantee, PAA will receive preference distributions totaling $1.0 million over ten years from PAA/Vulcan (distributions that would otherwise have been paid to Vulcan Gas Storage LLC). We believe that the fair value of the obligation to stand ready to perform is minimal. In addition, we believe the probability that we would be required to perform under the guaranty is extremely remote; however, there is no dollar limitation on potential future payments that fall under this obligation.
            PAA/Vulcan will reimburse us for the allocated costs of PAA’s non-officer staff associated with the management andday-to-day operations of PAA/Vulcan and allout-of-pocket costs. In addition, in the first fiscal year that EBITDA (as defined in the PAA/Vulcan LLC agreement) of PAA/Vulcan exceeds $75.0 million, we will receive a distribution from PAA/Vulcan equal to $6.0 million per year for each year since formation of the joint venture, subject to a maximum of 5 years or $30 million. Thereafter, we will receive annually a distribution equal to the greater of $2 million per year or two percent of the EBITDA of PAA/Vulcan.
            Other
            Thomas Coiner, an employee in our marketing department, is the son of George R. Coiner, Senior Group Vice President. In 2006, Thomas Coiner received compensation in excess of $120,000.
            Review, Approval or Ratification of Transactions with Related Persons
            Pursuant to our Governance Guidelines, a director is expected to bring to the attention of the CEO or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of Wachovia Investors, Inc.,the director, on the one hand, and the Partnership or GP LLC on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board in light of the circumstances, be determined by a majority of the disinterested directors.
            If a conflict or potential conflict of interest arises between the Partnership and GP LLC, the resolution of any such conflict or potential conflict should be addressed by the board in accordance with the provisions of the Partnership Agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a “conflicts committee” meeting the definitional requirements for such a committee under the Partnership Agreement. Such resolution may include resolution of any derivative conflicts created by an executive officer’s ownership of interests in GP LLC or a director’s appointment by an owner of GP LLC.
            Pursuant to our Code of Business Conduct, any Executive Officer must avoid conflicts of interest unless approved by the board of directors.
            In the case of any sale of equity in which owns a portion of our general partner interest, participated as an underwriter in our December offering of units and earned underwriting discounts and commissions of approximately $614,000. Anowner or affiliate of KAFU Holdings, L.P., anotheran owner of our general partner interest, also participated in that offering, earning commissionsparticipates, our practice is to obtain general approval of approximately $340,000. An affiliatethe full board for the transaction. The board typically delegates authority to set the specific terms to a pricing committee, consisting of Wachovia Investors, Inc. is also a lender under our bank credit facility.

            Item 14.Principal Accountant Feesthe CEO and Services

            one independent director. Actions by the pricing committee require unanimous approval.

            Item 14.Principal Accountant Fees and Services
            All services provided by our independent auditor are subject to pre-approval by our Audit Committee.audit committee. The Audit Committeeaudit committee has instituted a policy that describes certain pre-approved non-audit services. We believe that the


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            description of services is designed to be sufficiently detailed as to particular services provided, such that (i) management is not required to exercise judgment as to whether a proposed service fits within the description and (ii) the Audit Committeeaudit committee knows what services it is being asked to pre-approve. The Audit Committeeaudit committee is informed of each engagement of the independent auditor to provide services under the policy.

            The following table details expenditures paid tothe aggregate fees billed for professional services rendered by our independent auditorauditor: (in thousands):

            millions)
             
            		 Year Ended December 31,
             
            		 2003
            		 2002
            Audit fees $852 $748
            Audit-related fees  147  265
            Tax fees  401  381
            All other fees  315  690
              
            		 
            Total $1,715 $2,084
              
            		 

                    Expenditures classified as Audit fees above include those related to our annual audit, audits of our general partner and certain joint ventures of which we are the operator, and work performed on our registration of publicly-held debt and equity. Audit related fees are primarily comprised of work performed related to our benefit plans and "carve-outs" of acquired companies. The expenditures related to tax processing as well as the preparation of Form K-1 for our unitholders are included in Tax fees. All other fees consist of those associated with due diligence performed on potential acquisitions and certain risk management projects.

                     
              Year Ended
            		 
              December 31, 
              2006  2005 
             
            Audit fees(1) $2.4  $2.2 
            Audit-related fees(2)  0.3   0.1 
            Tax fees(3)  1.6   0.5 
            All other fees(4)  0.9   0.3 
                     
            Total $5.2  $3.1 
                     

            (1)Audit fees include those related to our annual audit (including internal control evaluation and reporting), audits of our general partner and certain joint ventures of which we are the operator, and work performed on our registration of publicly-held debt and equity.
            (2)Audit-related fees primarily relate to audits of our benefit plans and carve-out audits of acquired companies.
            (3)Tax fees are related to tax processing as well as the preparation ofForms K-1 for our unitholders and includes incremental activity assumed with the issuance ofForms K-1 for former Pacific unitholders.
            (4)All other fees primarily consist of those associated with due diligence performed on our behalf and evaluating potential acquisitions.


            PART IV

            Item 15.  Exhibits Financial Statement Schedules and Reports on Form 8-K

            (a)(1) and (2)Financial Statements and Financial Statement Schedules

            (a) (1) Financial Statements
            See "Index“Index to the Consolidated Financial Statements"Statements” set forth onPage F-1.

            (2) Financial Statement Schedules
            All schedules are omitted because they are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
            (3) Exhibits
                   
             3.1 — Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of June 27, 2001 (incorporated by reference to Exhibit 3.1 toForm 8-K filed August 27, 2001).
             3.2 — Amendment No. 1 dated April 15, 2004 to the Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
             3.3 — Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
             3.4 — Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
             3.5 — Certificate of Incorporation of PAA Finance Corp. (incorporated by reference to Exhibit 3.6 to the Registration Statement onForm S-3 filed August 27, 2001).


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            (a)(3)Exhibits

                   
             3.6 — Bylaws of PAA Finance Corp. (incorporated by reference to Exhibit 3.7 to the Registration Statement onForm S-3 filed August 27, 2001).
             3.7 — Second Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC, dated September 12, 2005 (incorporated by reference to Exhibit 3.1 to the Current Report onForm 8-K filed September 16, 2005).
             3.8 — Second Amended and Restated Limited Partnership Agreement of Plains AAP, L.P., dated September 12, 2005 (incorporated by reference to Exhibit 3.2 to the Current Report onForm 8-K filed September 16, 2005).
             3.9 — Amendment No. 2 dated November 15, 2006 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report onForm 8-K filed November 21, 2006).
             3.10† — Certificate of Incorporation of Pacific Energy Finance Corporation.
             3.11† — Bylaws of Pacific Energy Finance Corporation.
             4.1 — Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.1 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2002).
             4.2 — First Supplemental Indenture (Series A and Series B 7.75% Senior Notes due 2012) dated as of September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.2 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2002).
             4.3 — Second Supplemental Indenture (Series A and Series B 5.625% Senior Notes due 2013) dated as of December 10, 2003 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.4 to the Annual Report onForm 10-K for the year ended December 31, 2003).
             4.4 — Third Supplemental Indenture (Series A and Series B 4.75% Senior Notes due 2009) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.4 to the Registration Statement onForm S-4, FileNo. 333-121168).
             4.5 — Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2016) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.5 to the Registration Statement onForm S-4, FileNo. 333-121168).
             4.6 — Class C Common Unit Purchase Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.L.P., Tortoise Energy Infrastructure Corporation and Vulcan Energy II Inc. dated March 31, 2004 (incorporated by reference to Exhibit 4.2 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
             4.7 — Registration Rights Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson MLP Fund, L.P., Tortoise Energy Infrastructure Corporation and Vulcan Energy II Inc. dated April 15, 2004 (incorporated by reference to Exhibit 4.1 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
             4.8 — Fifth Supplemental Indenture (Series A and Series B 5.25% Senior Notes due 2015) dated May 27, 2005 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed May 31, 2005).
             4.9 — Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated as of May 12, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp. and subsidiary guarantors signatory thereto and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed May 12, 2006).


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             4.10 — Seventh Supplemental Indenture, dated as of May 12, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains LPG Services GP LLC, Plains LPG Services, L.P. and Lone Star Trucking, LLC and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report onForm 8-K filed May 12, 2006).
             4.11 — Eighth Supplemental Indenture, dated as of August 25, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing International GP LLC, Plains Marketing International, L.P. and Plains LPG Marketing, L.P. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed August 25, 2006).
             4.12 — Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017), dated as of October 30, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp. and subsidiary guarantors signatory thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed October 30, 2006).
             4.13 — Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037), dated as of October 30, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp. and subsidiary guarantors signatory thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report onForm 8-K filed October 30, 2006).
             4.14 — Eleventh Supplemental Indenture dated November 15, 2006 to Indenture dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp., PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Pacific Energy Finance Corporation, Rangeland Marketing Company and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed November 21, 2006).
             4.15 — Indenture dated June 16, 2004 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 71/8% senior notes due 2014 (incorporated by reference to Exhibit 4.21 to Pacific’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004).
             4.16 — First Supplemental Indenture dated March 3, 2005 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 71/8% senior notes due 2014 (incorporated by reference to Exhibit 4.1 to Pacific’s Current Report onForm 8-K filed March 9, 2005).
             4.17† — Second Supplemental Indenture dated September 23, 2005 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 71/8% senior notes due 2014.
             4.18 — Third Supplemental Indenture dated November 15, 2006 to Indenture dated as of June 16, 2004, among Plains All American Pipeline, L.P., Pacific Energy Finance Corporation, PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Rangeland Marketing Company, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, Plains Marketing Canada, L.P., PMC (Nova Scotia) Company, Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains Marketing International L.P., Plains LPG Marketing, L.P., PAA Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report onForm 8-K filed November 21, 2006).


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             4.19 — Indenture dated September 23, 2005 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 61/4% senior notes due 2015 (incorporated by reference to Exhibit 4.1 to Pacific’s Current Report onForm 8-K filed September 28, 2005).
             4.20 — First Supplemental Indenture dated November 15, 2006 to Indenture dated as of September 23, 2005, among Plains All American Pipeline, L.P., Pacific Energy Finance Corporation, PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Rangeland Marketing Company, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, Plains Marketing Canada, L.P., PMC (Nova Scotia) Company, Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains Marketing International L.P., Plains LPG Marketing, L.P., PAA Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report onForm 8-K filed November 21, 2006).
             4.21 — Registration Rights Agreement dated as of July 26, 2006 among Plains All American Pipeline, L.P., Vulcan Capital Private Equity I LLC, Kayne Anderson MLP Investment Company and Kayne Anderson Energy Total Return Fund, Inc. (incorporated by reference to Exhibit 4.13 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2006).
             4.22 — Registration Rights Agreement dated as of December 19, 2006 among Plains All American Pipeline, L.P.,E-Holdings III, L.P.,E-Holdings V, L.P., Kayne Anderson MLP Investment Company and Kayne Anderson Energy Development Company (incorporated by reference to Exhibit 4.6 to the Registration Statement onForm S-3/A, File No,333-138888).
             4.23 — Exchange and Registration Rights Agreement dated as of October 30, 2006, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains LPG Marketing, L.P., Plains Marketing International, L.P., Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, BNP Paribas Securities Corp., SunTrust Capital Markets, Inc., Fortis Securities LLC, Scotia Capital (USA) Inc., Comerica Securities, Inc., Commerzbank Capital Markets Corp., Daiwa Securities America Inc., DnB NOR Markets, Inc., HSBC Securities (USA) Inc., ING Financial Markets LLC, Mitsubishi UFJ Securities International plc, Piper Jaffray & Co., RBC Capital Markets Corporation, SG Americas Securities, LLC, Wedbush Morgan Securities Inc. and Wells Fargo Securities, LLC relating to the 2017 Notes (incorporated by reference to Exhibit 4.3 to the Current Report onForm 8-K filed October 30, 2006).
             4.24 — Exchange and Registration Rights Agreement dated as of October 30, 2006, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains LPG Marketing, L.P., Plains Marketing International, L.P., Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, BNP Paribas Securities Corp., SunTrust Capital Markets, Inc., Fortis Securities LLC, Scotia Capital (USA) Inc., Comerica Securities, Inc., Commerzbank Capital Markets Corp., Daiwa Securities America Inc., DnB NOR Markets, Inc., HSBC Securities (USA) Inc., ING Financial Markets LLC, Mitsubishi UFJ Securities International plc, Piper Jaffray & Co., RBC Capital Markets Corporation, SG Americas Securities Inc. and Wells Fargo Securities, LLC relating to the 2037 Notes (incorporated by reference to Exhibit 4.4 to the Current Report onForm 8-K filed October 30, 2006).


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             10.1 — Second Amended and Restated Credit Agreement dated as of July 31, 2006 by and among Plains All American Pipeline, L.P., as US Borrower; PMC (Nova Scotia) Company and Plains Marketing Canada, L.P., as Canadian Borrowers; Bank of America, N.A., as Administrative Agent; Bank of America, N.A., acting through its Canada Branch, as Canadian Administrative Agent; Wachovia Bank, National Association and JPMorgan Chase Bank, N.A., as Co-Syndication Agents; Fortis Capital Corp., Citibank, N.A., BNP Paribas, UBS Securities LLC, SunTrust Bank, and The Bank of Nova Scotia, as Co-Documentation Agents; the Lenders party thereto; and Banc of America Securities LLC and Wachovia Capital Markets, LLC , as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed August 4, 2006).
             10.2 — Restated Credit Facility (Uncommitted Senior Secured Discretionary Contango Facility) dated November 19, 2004 among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed November 24, 2004).
             10.3 — Amended and Restated Crude Oil Marketing Agreement, dated as of July 23, 2004, among Plains Resources Inc., Calumet Florida Inc. and Plains Marketing, L.P. (incorporated by reference to Exhibit 10.2 to the Quarterly Report onForm 10-Q for the quarter ended June 30, 2004).
             10.4 — Amended and Restated Omnibus Agreement, dated as of July 23, 2004, among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., Plains Pipeline, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Quarterly Report onForm 10-Q for the quarter ended June 30, 2004).
             10.5 — Contribution, Assignment and Amendment Agreement, dated as of June 27, 2001, among Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P., Plains All American GP LLC and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed June 27, 2001).
             10.6 — Contribution, Assignment and Amendment Agreement, dated as of June 8, 2001, among Plains All American Inc., Plains AAP, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed June 11, 2001).
             10.7 — Separation Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc., Plains All American GP LLC, Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 10.2 to the Current Report onForm 8-K filed June 11, 2001).
             10.8** — Pension and Employee Benefits Assumption and Transition Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Current Report onForm 8-K filed June 11, 2001).
             10.9** — Plains All American GP LLC 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed January 26, 2005).
             10.10** — Plains All American GP LLC 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registration Statement onForm S-8, FileNo. 333-74920) as amended June 27, 2003 (incorporated by reference to Exhibit 10.1 to the Quarterly Report onForm 10-Q for the quarter ended June 30, 2003).
             10.11** — Plains All American 2001 Performance Option Plan (incorporated by reference to Exhibit 99.2 to the Registration Statement onForm S-8, FileNo. 333-74920).
             10.12** — Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.1 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2001).
             10.13** — Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.2 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2001).
             10.14 — Asset Purchase and Sale Agreement dated February 28, 2001 between Murphy Oil Company Ltd. and Plains Marketing Canada, L.P. (incorporated by reference to Exhibit 99.1 to the Current Report onForm 8-K filed May 10, 2001).
             10.15 — Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to the Registration Statement onForm S-1, FileNo. 333-64107).


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             10.16 — Transportation Agreement dated August 2, 1993, among All American Pipeline Company, Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to the Registration Statement onForm S-1, FileNo. 333-64107).
             10.17 — First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to the Annual Report onForm 10-K for the year ended December 31, 1998).
             10.18 — Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to the Annual Report onForm 10-K for the year ended December 31, 1998).
             10.19** — Plains All American Inc. 1998 Management Incentive Plan (incorporated by reference to Exhibit 10.5 to the Annual Report onForm 10-K for the year ended December 31, 1998).
             10.20** — PMC (Nova Scotia) Company Bonus Program (incorporated by reference to Exhibit 10.20 to the Annual Report onForm 10-K for the year ended December 31, 2004).
             10.21** — Quarterly Bonus Summary (incorporated by reference to Exhibit 10.21 to the Annual Report onForm 10-K for the year ended December 31, 2005).
             10.22**† — Directors’ Compensation Summary.
             10.23 — Master Railcar Leasing Agreement dated as of May 25, 1998 (effective June 1, 1998), between Pivotal Enterprises Corporation and CANPET Energy Group, Inc., (incorporated by reference to Exhibit 10.16 to the Annual Report onForm 10-K for the year ended December 31, 2001).
             10.24** — Form of LTIP Grant Letter (Armstrong/Pefanis) (incorporated by reference to Exhibit 10.24 to the Annual Report onForm 10-K for the year ended December 31, 2005).
             10.25** — Form of LTIP Grant Letter (executive officers) (incorporated by reference to Exhibit 10.3 to the Current Report onForm 8-K filed April 1, 2005).
             10.26** — Form of LTIP Grant Letter (independent directors) (incorporated by reference to Exhibit 10.3 to the Current Report onForm 8-K filed February 23, 2005).
             10.27** — Form of LTIP Grant Letter (designated directors) (incorporated by reference to Exhibit 10.4 to the Current Report onForm 8-K filed February 23, 2005).
             10.28** — Form of LTIP Grant Letter (payment to entity) (incorporated by reference to Exhibit 10.5 to the Current Report onForm 8-K filed February 23, 2005).
             10.29** — Form of Option Grant Letter (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed April 1, 2005).
             10.30 — Administrative Services Agreement between Plains All American Pipeline Company and Vulcan Energy Corporation, dated October 14, 2005 (incorporated by reference to Exhibit 1.1 to the Current Report onForm 8-K filed October 19, 2005).
             10.31 — Amended and Restated Limited Liability Company Agreement of PAA/Vulcan Gas Storage, LLC, dated September 13, 2005 (incorporated by reference to Exhibit 1.1 to the Current Report onForm 8-K filed September 19, 2005).
             10.32 — Membership Interest Purchase Agreement by and between Sempra Energy Trading Corp. and PAA/Vulcan Gas Storage, LLC, dated August 19, 2005 (incorporated by reference to Exhibit 1.2 to the Current Report onForm 8-K filed September 19, 2005).
             10.33** — Waiver Agreement dated as of August 12, 2005 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed August 16, 2005).
             10.34** — Waiver Agreement dated as of August 12, 2005 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.2 to the Current Report onForm 8-K filed August 16, 2005).
             10.35 — Excess Voting Rights Agreement dated as of August 12, 2005 between Vulcan Energy GP Holdings Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Current Report onForm 8-K filed August 16, 2005).


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             10.36 — Excess Voting Rights Agreement dated as of August 12, 2005 between Lynx Holdings I, LLC and Plains All American GP LLC (incorporated by reference to Exhibit 10.4 to the Current Report onForm 8-K filed August 16, 2005).
             10.37 — First Amendment dated as of April 20, 2005 to Restated Credit Agreement, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed April 21, 2005).
             10.38 — Second Amendment dated as of May 20, 2005 to Restated Credit Agreement, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed May 12, 2005).
             10.39** — Form of LTIP Grant Letter (executive officers) (incorporated by reference to Exhibit 10.39 to the Annual Report onForm 10-K for the year ended December 31, 2005).
             10.40** — Employment Agreement between Plains All American GP LLC and John vonBerg dated December 18, 2001 (incorporated by reference to Exhibit 10.40 to the Annual Report onForm 10-K for the year ended December 31, 2005).
             10.41 — Third Amendment dated as of November 4, 2005 to Restated Credit Agreement, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.41 to the Annual Report onForm 10-K for the year ended December 31, 2005).
             10.42† — Fourth Amendment dated as of November 16, 2006 to Restated Credit Agreement, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto.
             10.43 — First Amendment dated May 9, 2006 to the Amended and Restated Limited Liability Company Agreement of PAA/Vulcan Gas Storage, LLC dated September 13, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed May 15, 2006).
             10.44** — Form of LTIP Grant Letter (audit committee members) (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed August 23, 2006).
             10.45†** — Plains All American PPX Successor Long-Term Incentive Plan.
             10.46 — Interim364-Day Credit Agreement dated as of July 31, 2006 by and among Plains All American Pipeline, L.P., as Borrower; JPMorgan Chase Bank, N.A., as Administrative Agent; Bank of America, N.A. and Citibank, N.A., as Co-Syndication Agents; Wachovia Bank, National Association and UBS Securities LLC, as Co-Documentation Agents; the Lenders party thereto; and JPMorgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers (incorporated by reference to Exhibit 10.2 to the Current Report onForm 8-K filed August 4, 2006).
             10.47** — Forms of LTIP Grant Letters (executive officers) - February 2007 awards (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed February 28, 2007).
             21.1† — List of Subsidiaries of Plains All American Pipeline, L.P.
             23.1† — Consent of PricewaterhouseCoopers LLP.
             31.1† — Certification of Principal Executive Officer pursuant to Exchange ActRules 13a-14(a) and15d-14(a).
             31.2† — Certification of Principal Financial Officer pursuant to Exchange ActRules 13a-14(a) and15d-14(a).
             32.1† — Certification of Principal Executive Officer pursuant to 18 USC 1350.
             32.2† — Certification of Principal Financial Officer pursuant to 18 USC 1350.
            3.1—Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. dated as of June 27, 2001, (incorporated by reference to Exhibit 3.1).

            3.2†

            —
            Second Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of June 27, 2001 (incorporated by reference to Exhibit 3.2 to Form 8-K filed August 27, 2001).

            3.3

            —
            Second Amended and Restated Agreement of Limited Partnership of All American Pipeline, L.P. dated as of June 27, 2001 (incorporated by reference to Exhibit 3.3 Form 8-K filed August 27, 2001).

            3.4

            —
            Certificate of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.4 to Registration Statement, file No. 333-64107).

            3.5

            —
            Certificate of Limited Partnership of Plains Marketing, L.P. dated as of November 10, 1998 (incorporated by reference to Exhibit 3.5 to Annual Report on Form 10-K for the Year Ended December 31, 1998).

            3.6

            —
            Articles of Conversion of All American Pipeline Company dated as of November 10, 1998 (incorporated by reference to Exhibit 3.5 to Annual Report on Form 10-K for the Year Ended December 31, 1998).

            3.7

            —
            Amended and Restated Limited Partnership Agreement of Plains AAP, L.P., dated as of June 8, 2001 (incorporated by reference to Exhibit 3.1 to Form 8-K filed June 11, 2001).

            3.8

            —
            Amended and Restated Limited Liability Company Agreement of Plains All American GP, LLC dated as of June 8, 2001, as amended by first Amendment dated September 16, 2003 (incorporated by reference to Exhibit 3.1 to Quarterly Form 10-Q for the period ended September 30, 2003).

            4.1

            —
            Registration Rights Agreement, dated as of June 8, 2001, among Plains All American Pipeline, L.P., Sable Holdings, L.P., E-Holdings III, L.P., KAFU Holdings, LP, PAA Management, L.P., Mark E. Strome, Strome Hedgecap Fund, L.P., John T. Raymond and Plains All American Inc. (incorporated by reference to Exhibit 4.1 to Form 8-K filed June 11, 2001).

            4.2

            —
            Indenture dated as of September 25, 2002 (incorporated by reference to Exhibit 4.1 to Quarterly Report on Form 10-Q for the Quarter ended September 30, 2002).

            4.3

            —
            First Supplemental Indenture dated as of September 25, 2002 (incorporated by reference to Exhibit 4.2 to Quarterly Report on Form 10-Q for the Quarter ended September 30, 2002).

            †4.4

            —
            Second Supplemental Indenture dated as of December 10, 2003.

            †4.5

            —
            Registration Rights Agreement dated December 10, 2003.Filed herewith
             
            **Management compensatory plan or arrangement



            133


            10.01

            —
            Contribution, Assignment and Amendment Agreement, dated as of June 27, 2001, among Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P., Plains All American GP LLC and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K filed June 27, 2001).

            10.02

            —
            Contribution, Assignment and Amendment Agreement, dated as of June 8, 2001, among Plains All American Inc., Plains AAP, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.1 to Form 8-K filed June 11, 2001).

            10.03

            —
            Separation Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc., Plains All American GP LLC, Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 10.2 to Form 8-K filed June 11, 2001).

            10.04

            —
            Pension and Employee Benefits Assumption and Transition Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to Form 8-K filed June 11, 2001).

            **10.05

            —
            Plains All American GP LLC 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registration Statement on Form S-8, File No. 333-74920) as amended June 27, 2003 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the period ended June 30, 2003).

            **10.06

            —
            Plains All American 2001 Performance Option Plan (incorporated by reference to Exhibit 99.2 to Registration Statement on Form S-8, File No. 333-74920).

            **10.07

            —
            Phantom MLP unit Agreement for Greg L. Armstrong (incorporated by reference to Exhibit 99.3 to Registration Statement on Form S-8, File No. 333-74920).

            **10.08

            —
            Phantom MLP Unit Agreement for Phillip D. Kramer (incorporated by reference to Exhibit 99.5 to Registration Statement on Form S-8, File No. 333-74920).

            **10.09

            —
            Phantom MLP Unit Agreement for Tim Moore (incorporated by reference to Exhibit 99.6 to Registration Statement on Form S-8, File No. 333-74920).

            **10.10

            —
            Phantom MLP Unit Agreement for Harry N. Pefanis (incorporated by reference to Exhibit 99.7 to Registration Statement on Form S-8, File No. 333-74920).

            **10.11

            —
            Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2001).

            **10.12

            —
            Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.4 to Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2001).

            10.13

            —
            Asset Purchase and Sale Agreement between Murphy Oil Company Ltd. And Plains Marketing Canada, L.P. (incorporated by reference to Form 8-K filed May 10, 2001).

            10.14

            —
            Crude Oil Marketing Agreement among Plains Resources Inc., Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.07 to Annual Report on Form 10-K for the Year Ended December 31, 1998).


            10.15

            —
            Omnibus Agreement among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., and Plains All American Inc. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.08 to Annual Report on Form 10-K for the Year Ended December 31, 1998).

            10.16

            —
            Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to Registration Statement, file No. 333-64107).

            10.17

            —
            Transportation Agreement dated August 2, 1993, between All American Pipeline Company and Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to Registration Statement, File No. 333-64107).

            10.18

            —
            First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1998).

            10.19

            —
            Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to Annual Report on Form 10-K for the Year Ended December 31, 1998).

            †10.20

            —
            364-Day Revolving Credit Agreement dated November 21, 2003 among Plains All American Pipeline, L.P and Fleet National Bank and certain other lenders.

            †10.21

            —
            Uncommitted Senior Secured Discretionary Contango Credit Agreement dated November 21, 2003 among Plains Marketing, L.P. and Fleet National Bank and certain other lenders.

            †10.22

            —
            US/Canada Revolving Credit Agreement dated November 21, 2003 among Plains All American Pipeline, L.P, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P. and Fleet National Bank and certain other lenders.

            *23.1

            —
            Consent of Independent Registered Public Accounting Firm

            *31.1

            —
            Certification of Principal Executive Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)

            *31.2

            —
            Certification of Principal Financial Officer pursuant to Exchange Act rules 13a-14(a) and 15d-14(a)

            *32.1

            —
            Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350.

            *32.2

            —
            Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350
            †
            Previously filed

            *
            Filed herewith

            **
            Management contract or compensatory plan or arrangement

            (b)   Reports on Form 8-K

                    A Current Report on Form 8-K was furnished on February 24, 2004, in connection with disclosure of first quarter estimates and earnings guidance.

                    A Current Report on Form 8-K was filed on January 15, 2004 with an unaudited balance sheet of Plains AAP, L.P., as of September 30, 2003, attached as an exhibit.



                    A Current Report on Form 8-K was filed on December 22, 2003 with an underwriting agreement for an equity offering attached as an exhibit.

                    A Current Report on Form 8-K was filed on December 17, 2003 in connection with our disclosure of entering into an agreement to purchase the interests of Shell Pipeline Company' L.P.'s interests in certain pipeline systems.

                    A Current Report on Form 8-K was filed and furnished on December 17, 2003 in connection with our disclosure of the status of our acquisition activities.

                    A Current Report on Form 8-K was furnished on December 9, 2003, in connection with disclosure of our presentation at the Wachovia Securities Pipeline Conference and Symposium.

                    A Current Report on Form 8-K was furnished on December 3, 2003, in connection with the private offering of $250 million of 5.625% senior notes.

                    A Current Report on Form 8-K/A was furnished on October 29, 2003 to correct certain inaccuracies in the Current Report furnished on October 28, 2003.

                    A Current Report on Form 8-K was furnished on October 28, 2003, in connection with disclosure of our third-quarter results and fourth-quarter forecasts.

                    A Current Report on Form 8-K was furnished on October 7, 2003, in connection with our disclosure of our presentation at the IPAA's 2003 Oil & Gas Investment Symposium West.

                    A Current Report on Form 8-K was furnished on September 24, 2003, in connection with our disclosure of our presentation at the Herold's 12th Annual Pacesetters Energy Conference.SIGNATURES

                    A Current Report on Form 8-K was furnished on September 16, 2003, in connection with our disclosure of our presentation at the RBC Capital Markets North American Energy and Power Conference.

                    A Current Report on Form 8-K was filed on September 10, 2003 with an underwriting agreement for an equity offering attached as an exhibit.

                    A Current Report on Form 8-K was furnished on September 8, 2003, in connection with the announcement of an equity offering.



            SIGNATURES

            Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

            Plains All American Pipeline, L.P.
            By:  Plains AAP, L.P.,
            its general partner
            By:  Plains All American GP LLC,
            its general partner
            By: 
            /s/  Greg L. Armstrong
            Greg L. Armstrong,
            Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC (Principal Executive Officer)
            March 1, 2007
            By: 
            /s/  Phillip D. Kramer
            Phillip D. Kramer,
            Executive Vice President and Chief Financial Officer of Plains All American GP LLC
            (Principal Financial Officer)
            March 1, 2007
            Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
              PLAINS ALL AMERICAN PIPELINE, L.P.

            Name

             
            By:
            Title

            PLAINS AAP, L.P.,
            its general partner
            Date



            By:
            PLAINS ALL AMERICAN GP LLC,
            its general partner

            Date: July 16, 2004

            By:

            /s/              GREG L. ARMSTRONG      
            Greg L. Armstrong

            Greg L. Armstrong            		Chairman of the Board, Chief Executive Officer and Director of
            Plains All American GP LLC (Principal
            (Principal Executive Officer)            		March 1, 2007

            Date: July 16, 2004
             
            By:

            /s/  Harry N. Pefanis
            PHILLIP D. KRAMER      
            Harry N. Pefanis            		President and Chief Operating Officer of Plains All American GP LLCMarch 1, 2007
            /s/  Phillip D. Kramer

            Phillip D. Kramer            		Executive Vice President and Chief Financial Officer of
            Plains All American GP LLC (Principal
            (Principal Financial Officer)            		March 1, 2007
            /s/  Tina L. Val

            Tina L. Val            		Vice President — Accounting and Chief Accounting Officer of
            Plains All American GP LLC
            (Principal Accounting Officer)            		March 1, 2007


            134

            Name
            Title
            Date
            /s/  David N. Capobianco

            David N. Capobianco            		Director of
            Plains All American
            GP LLC            		March 1, 2007
            /s/  Everardo Goyanes

            Everardo Goyanes            		Director of
            Plains All American
            GP LLC            		March 1, 2007
            /s/  Gary R. Petersen

            Gary R. Petersen            		Director of
            Plains All American
            GP LLC            		March 1, 2007
            /s/  Robert V. Sinnott

            Robert V. Sinnott            		Director of
            Plains All American
            GP LLC            		March 1, 2007
            /s/  Arthur L. Smith

            Arthur L. Smith            		Director of
            Plains All American
            GP LLC            		March 1, 2007
            /s/  J. Taft Symonds

            J. Taft Symonds            		Director of
            Plains All American
            GP LLC            		March 1, 2007


            135


            PLAINS ALL AMERICAN PIPELINE, L.P.

            AND SUBSIDIARIES
            INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS


            Page
            Consolidated Financial Statements  
            Management’s Report on Internal Control Over Financial Reporting
            		F-2
            Report of Independent Registered Public Accounting Firm
            		 F-2F-3
            Consolidated Balance Sheets as of December 31, 20032006 and 20022005
            		 F-3F-5
            Consolidated Statements of Operations for the years ended December 31, 2003, 20022006, 2005 and 20012004
            		 F-4F-6
            Consolidated Statements of Cash Flows for the years ended December 31, 2003, 20022006, 2005 and 20012004
            		 F-5F-7
            Consolidated StatementStatements of Changes in Partners'Partners’ Capital for the years ended December 31, 2003, 20022006, 2005 and 20012004
            		 F-6F-8
            Consolidated Statements of Comprehensive Income for the years ended December 31, 2003, 20022006, 2005 and 20012004
            		 F-7F-9
            Consolidated StatementStatements of Changes in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 20032006, 2005 and 20022004
            		 F-7F-10
            Notes to the Consolidated Financial Statements
            		 F-8F-11


            F-1

            MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
            Plains All American Pipeline, L.P.’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
            Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
            Management has used the framework set forth in the report entitled “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Partnership’s internal control over financial reporting. Based on that evaluation, management has concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2006. This evaluation did not include the internal control over financial reporting related to the purchase business combination of the operations acquired in conjunction with the Pacific merger on November 15, 2006 (the “Pacific Acquisition”). The revenues for the year ended December 31, 2006 and the total assets as of December 31, 2006 recorded for the Pacific Acquisition operations as a percentage of the Partnership’s revenues and total assets represent approximately 1% and 29%, respectively. Management’s assessment of the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
            /s/  Greg L. Armstrong
            Greg L. Armstrong
            Chairman of the Board, Chief Executive Officer and Director of Plains All American GP LLC
            (Principal Executive Officer)
            /s/  Phillip D. Kramer
            Phillip D. Kramer
            Executive Vice President and Chief Financial Officer of Plains All American GP LLC
            (Principal Financial Officer)
            March 1, 2007


            F-2


            Report of Independent Registered Public Accounting Firm

            To the Board of Directors of the General Partner and Unitholders of
            Plains All American Pipeline, L.P.:

            We have completed integrated audits of Plains All American Pipeline, L.P.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
            Consolidated financial statements
            In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows, of changes in partners'partners’ capital, of comprehensive income and of changes in accumulated other comprehensive income (loss) present fairly, in all material respects, the financial position of Plains All American Pipeline, L.P. and its subsidiaries (the "Partnership") at December 31, 20032006 and 2002,2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 20032006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; ourPartnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States), which. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

            As discussed in NoteNotes 1 and 2 to the consolidated financial statements, the Partnership changed the manner in which it accounts for pipeline linefill in 2004 and the manner in which it accounts for equity-based compensation and purchases and sales with the same counterparty in 2006.
            Internal control over financial reporting
            Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Partnership maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established inInternal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established inInternal Control — Integrated Frameworkissued by the COSO. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its methodassessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Partnership’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
            A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made


            F-3

            only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
            Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate
            As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded the businesses acquired in the acquisition of Pacific Energy Partners, L.P. (the “Pacific Acquisition”) from its assessment of internal control over financial reporting as of December 31, 2006 because these businesses were acquired by the Partnership in a purchase business combination during 2006. We have also excluded the Pacific Acquisition from our audit of internal control over financial reporting. Pacific Acquisition are wholly-owned businesses whose total assets and total revenues represent 29% and 1%, respectively, of the related consolidated financial statement amounts as of and for derivative instruments and hedging activities effective January 1, 2001.

            the year ended December 31, 2006.

            PricewaterhouseCoopers LLP

            Houston, Texas
            February 26, 2004


            March 1, 2007


            F-4


            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

            CONSOLIDATED BALANCE SHEETS

            (in thousands, except unit data)

             
            		 December 31,
            2003
            		 December 31,
            2002
            		 
            ASSETS 

            CURRENT ASSETS
             
             
             
             
             
             
             
            Cash and cash equivalents $4,137 $3,501 
            Accounts receivable, net  590,645  499,909 
            Inventory  105,967  81,849 
            Other current assets  32,225  17,676 
              
            		 
            		 
             Total current assets  732,974  602,935 
              
            		 
            		 
            PROPERTY AND EQUIPMENT  1,272,634  1,030,303 
            Accumulated depreciation  (121,595) (77,550)
              
            		 
            		 
               1,151,039  952,753 
              
            		 
            		 
            OTHER ASSETS       
            Pipeline linefill  122,653  62,558 
            Other, net  88,965  48,329 
              
            		 
            		 
             Total assets $2,095,631 $1,666,575 
              
            		 
            		 
            LIABILITIES AND PARTNERS' CAPITAL 

            CURRENT LIABILITIES
             
             
             
             
             
             
             
            Accounts payable $603,460 $488,922 
            Due to related parties  26,981  23,301 
            Short-term debt (see Note 6)  127,259  99,249 
            Other current liabilities  44,219  25,777 
              
            		 
            		 
             Total current liabilities  801,919  637,249 
              
            		 
            		 
            LONG-TERM LIABILITIES       
            Long-term debt under credit facilities, including current maturities of $9,000 for the 2002 period  70,000  310,126 
            Senior notes, net of unamortized discount of $1,009 and $390, respectively  448,991  199,610 
            Other long-term liabilities and deferred credits  27,994  7,980 
              
            		 
            		 
             Total liabilities  1,348,904  1,154,965 
              
            		 
            		 
            COMMITMENTS AND CONTINGENCIES (NOTE 12)       

            PARTNERS' CAPITAL
             
             
             
             
             
             
             
            Common unitholders (49,502,556 and 38,240,939 units outstanding at December 31, 2003, and December 31, 2002, respectively)  744,073  524,428 
            Class B common unitholder (1,307,190 units outstanding at each date)  18,046  18,463 
            Subordinated unitholders (7,522,214 and 10,029,619 units outstanding at December 31, 2003, and December 31, 2002, respectively)  (39,913) (47,103)
            General partner  24,521  15,822 
              
            		 
            		 
             Total partners' capital  746,727  511,610 
              
            		 
            		 
              $2,095,631 $1,666,575 
              
            		 
            		 

                     
              December 31,
            		  December 31,
            		 
              2006  2005 
              (In millions, except units) 
             
            ASSETS
            CURRENT ASSETS
            		        
            Cash and cash equivalents $11.3  $9.6 
            Trade accounts receivable and other receivables, net  1,725.4   781.0 
            Inventory  1,290.0   910.3 
            Other current assets  130.9   104.3 
                     
            Total current assets  3,157.6   1,805.2 
                     
            PROPERTY AND EQUIPMENT
            		  4,190.1   2,116.1 
            Accumulated depreciation  (348.1)  (258.9)
                     
               3,842.0   1,857.2 
                     
            OTHER ASSETS
            		        
            Pipeline linefill in owned assets  265.5   180.2 
            Inventory in third-party assets  75.7   71.5 
            Investment in unconsolidated entities   183.0   121.7 
            Goodwill  1,026.2   47.4 
            Other, net  164.9   37.1 
                     
            Total assets $8,714.9  $4,120.3 
                     
             
            LIABILITIES AND PARTNERS’ CAPITAL
            CURRENT LIABILITIES
            		        
            Accounts payable and accrued liabilities $1,846.6  $1,300.4 
            Short-term debt  1,001.2   378.4 
            Other current liabilities  176.9   114.5 
                     
            Total current liabilities  3,024.7   1,793.3 
                     
            LONG-TERM LIABILITIES
            		        
            Long-term debt under credit facilities and other  3.1   4.7 
            Senior notes, net of unamortized net discount of $1.8 and $3.0, respectively  2,623.2   947.0 
            Other long-term liabilities and deferred credits  87.1   44.6 
                     
            Total liabilities  5,738.1   2,789.6 
                     
            COMMITMENTS AND CONTINGENCIES (NOTE 11)
            		        
            PARTNERS’ CAPITAL
            		        
            Common unitholders (109,405,178 and 73,768,576 units outstanding at December 31, 2006 and 2005, respectively)  2,906.1   1,294.1 
            General partner  70.7   36.6 
                     
            Total partners’ capital  2,976.8   1,330.7 
                     
              $8,714.9  $4,120.3 
                     
            The accompanying notes are an integral part of these consolidated financial statements.


            F-5



            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

            CONSOLIDATED STATEMENTS OF OPERATIONS

            (in thousands, except per unit data)

             
            		 Year Ended December 31,
            		 
             
            		 2003
            		 2002
            		 2001
            		 
            REVENUES          
            Crude oil and LPG sales $11,952,623 $7,892,162 $6,481,305 
            Pipeline margin activities  505,287  382,513  285,618 
            Pipeline tariffs and fees  99,887  79,939  54,234 
            Other  32,052  29,609  47,058 
              
            		 
            		 
            		 
             Total revenues  12,589,849  8,384,223  6,868,215 

            COSTS AND EXPENSES
             
             
             
             
             
             
             
             
             
             
            Crude oil and LPG purchases and related costs  11,727,355  7,726,323  6,338,365 
            Pipeline margin activities purchases  486,154  362,311  270,786 
            Other purchases  19,027  14,862  4,965 
            Field operating costs (excluding LTIP charge)  134,177  106,436  106,854 
            LTIP charge—operations  5,727  —  — 
            Inventory valuation adjustment  —  —  4,984 
            General and administrative (excluding LTIP charge)  49,969  45,663  46,586 
            LTIP charge—general and administrative  23,063  —  — 
            Depreciation and amortization  46,821  34,068  24,307 
              
            		 
            		 
            		 
             Total costs and expenses  12,492,293  8,289,663  6,796,847 
              
            		 
            		 
            		 
            Gains on sales of assets  648  —  984 
              
            		 
            		 
            		 
            OPERATING INCOME  98,204  94,560  72,352 
            OTHER INCOME/(EXPENSE)          
            Interest expense (net of capitalized interest of $524, $773 and $153)  (35,226) (29,057) (29,082)
            Interest income and other, net (Note 2)  (3,530) (211) 401 
              
            		 
            		 
            		 
            Income before cumulative effect of accounting change  59,448  65,292  43,671 
            Cumulative effect of accounting change  —  —  508 
              
            		 
            		 
            		 
            NET INCOME $59,448 $65,292 $44,179 
              
            		 
            		 
            		 
            NET INCOME-LIMITED PARTNERS $53,473 $60,912 $42,239 
              
            		 
            		 
            		 
            NET INCOME-GENERAL PARTNER $5,975 $4,380 $1,940 
              
            		 
            		 
            		 
            BASIC NET INCOME PER LIMITED PARTNER UNIT          

            Income before cumulative effect of accounting change
             
            $
            1.01
             
            $
            1.34
             
            $
            1.12
             
            Cumulative effect of accounting change  —  —  0.01 
              
            		 
            		 
            		 
            Net income $1.01 $1.34 $1.13 
              
            		 
            		 
            		 
            DILUTED NET INCOME PER LIMITED PARTNER UNIT          

            Income before cumulative effect of accounting change
             
            $
            1.00
             
            $
            1.34
             
            $
            1.12
             
            Cumulative effect of accounting change  —  —  0.01 
              
            		 
            		 
            		 
            Net Income $1.00 $1.34 $1.13 
              
            		 
            		 
            		 
            BASIC WEIGHTED AVERAGE UNITS OUTSTANDING  52,743  45,546  37,528 
              
            		 
            		 
            		 
            DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING  53,400  45,546  37,528 
              
            		 
            		 
            		 

                         
              Twelve Months Ended December 31, 
              2006  2005  2004 
              (In millions, except per unit data) 
             
            REVENUES
            		            
            Crude oil and LPG sales (includes buy/sell transactions of $4,717.7, $16,077.8, and $11,247.0, respectively) $21,406.9  $30,139.7  $20,184.3 
            Pipeline margin activities revenues (includes buy/sell transactions of $44.2, $197.1, and $149.8, respectively)  694.3   772.7   575.2 
            Pipeline tariff activities revenues  263.3   218.1   177.6 
            Other revenues  79.9   46.0   37.9 
                         
            Total revenues  22,444.4   31,176.5   20,975.0 
            COSTS AND EXPENSES
            		            
            Crude oil and LPG purchases and related costs (includes buy/sell transactions of $4,749.4, $15,910.3, and $11,137.7, respectively)  20,819.7   29,691.9   19,870.9 
            Pipeline margin activities purchases (includes buy/sell transactions of $45.7, $196.2, and $142.5, respectively  665.9   750.6   553.7 
            Field operating costs  369.8   272.5   219.5 
            General and administrative expenses  133.9   103.2   82.7 
            Depreciation and amortization  100.4   83.5   68.7 
                         
            Total costs and expenses  22,089.7   30,901.7   20,795.5 
                         
            OPERATING INCOME
            		  354.7   274.8   179.5 
                         
            OTHER INCOME/(EXPENSE)
            		            
            Equity earnings in unconsolidated entities  7.7   1.8   0.5 
            Interest expense (net of capitalized interest of $6.0, $1.8, and $0.5)  (85.6)  (59.4)  (46.7)
            Interest income and other income (expense), net  2.3   0.6   (0.2)
            Income tax expense  (0.3)  —   — 
                         
            Income before cumulative effect of change in accounting principle  278.8   217.8   133.1 
            Cumulative effect of change in accounting principle  6.3   —   (3.1)
                         
            NET INCOME
            		 $285.1  $217.8  $130.0 
                         
            NET INCOME-LIMITED PARTNERS
            		 $246.9  $198.8  $119.3 
                         
            NET INCOME-GENERAL PARTNER
            		 $38.2  $19.0  $10.7 
                         
            BASIC NET INCOME PER LIMITED PARTNER UNIT
            		            
            Income before cumulative effect of change in accounting principle $2.84  $2.77  $1.94 
            Cumulative effect of change in accounting principle  0.07   —   (0.05)
                         
            Net income $2.91  $2.77  $1.89 
                         
            DILUTED NET INCOME PER LIMITED PARTNER UNIT
            		            
            Income before cumulative effect of change in accounting principle $2.81  $2.72  $1.94 
            Cumulative effect of change in accounting principle  0.07   —   (0.05)
                         
            Net income $2.88  $2.72  $1.89 
                         
            BASIC WEIGHTED AVERAGE UNITS OUTSTANDING
            		  81.1   69.3   63.3 
                         
            DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING
            		  81.9   70.5   63.3 
                         
            The accompanying notes are an integral part of these consolidated financial statements.



            F-6


            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

            CONSOLIDATED STATEMENTS OF CASH FLOWS

            (in thousands)

             
            		 Year Ended December 31,
            		 
             
            		 2003
            		 2002
            		 2001
            		 
            CASH FLOWS FROM OPERATING ACTIVITIES          
            Net income $59,448 $65,292 $44,179 
            Adjustments to reconcile to cash flows from operating activities:          
             Depreciation and amortization  46,821  34,068  24,307 
             Gains on sales of assets  (648) —  (984)
             Cumulative effect of accounting change  —  —  (508)
             Noncash compensation expense  —  —  5,741 
             Allowance for doubtful accounts  360  146  3,000 
             Inventory valuation adjustment  —  —  4,984 
             Change in derivative fair value  (363) (243) (207)
             Net cash paid for termination of interest rate hedging instruments  (6,152) —  — 
             Write-off of unamortized debt issue costs  3,272  —  — 
             Noncash portion of LTIP charge (Note 11)  28,052  —  — 
            Changes in assets and liabilities, net of acquisitions:          
             Accounts receivable and other  (102,005) (136,480) (18,856)
             Inventory  (38,941) 105,944  (117,878)
             Pipeline linefill  (46,790) (11,060) (13,736)
             Accounts payable and other current liabilities  117,412  106,065  46,671 
             Other long-term liabilities and deferred credits  4,600  1,200  600 
             Due to related parties  3,452  8,962  (7,266)
              
            		 
            		 
            		 
              Net cash provided by (used in) operating activities  68,518  173,894  (29,953)
              
            		 
            		 
            		 

            CASH FLOWS FROM INVESTING ACTIVITIES
             
             
             
             
             
             
             
             
             
             
            Cash paid in connection with acquisitions (Note 3)  (168,359) (324,628) (229,162)
            Additions to property and equipment  (65,416) (40,590) (21,069)
            Proceeds from sales of assets  8,450  1,437  740 
              
            		 
            		 
            		 
              Net cash used in investing activities  (225,325) (363,781) (249,491)
              
            		 
            		 
            		 

            CASH FLOWS FROM FINANCING ACTIVITIES
             
             
             
             
             
             
             
             
             
             
            Net borrowings/(repayments) on short-term letter of credit and hedged inventory facilities  (6,197) (4,770) 99,583 
            Net borrowings/(repayments) on long-term revolving credit facilities  87,773  (42,144) 34,677 
            Principal payments on senior secured term loans (Note 6)  (297,000) (3,000) — 
            Cash paid in connection with financing arrangements  (5,191) (5,435) (6,351)
            Net proceeds from the issuance of common units (Note 7)  250,341  145,046  227,549 
            Proceeds from the issuance of senior unsecured notes (Note 6)  249,340  199,600  — 
            Distributions paid to unitholders and general partner (Note 7)  (121,822) (99,841) (75,929)
              
            		 
            		 
            		 
              Net cash provided by financing activities  157,244  189,456  279,529 
              
            		 
            		 
            		 

            Effect of translation adjustment on cash
             
             
            199
             
             
            421
             
             
            —
             

            Net increase (decrease) in cash and cash equivalents
             
             
            636
             
             
            (10
            )
             
            85
             
            Cash and cash equivalents, beginning of period  3,501  3,511  3,426 
              
            		 
            		 
            		 
            Cash and cash equivalents, end of period $4,137 $3,501 $3,511 
              
            		 
            		 
            		 

            Cash paid for interest, net of amounts capitalized
             
            $
            36,382
             
            $
            28,550
             
            $
            33,341
             
              
            		 
            		 
            		 

                         
              Year Ended December 31, 
              2006  2005  2004 
              (In millions) 
             
            CASH FLOWS FROM OPERATING ACTIVITIES
            		            
            Net income $285.1  $217.8  $130.0 
            Adjustments to reconcile to cash flows from operating activities:            
            Depreciation and amortization  100.4   83.5   68.7 
            Cumulative effect of change in accounting principle  (6.3)  —   3.1 
            Inventory valuation adjustment  5.9   —   2.0 
            SFAS 133mark-to-market adjustment
            		  4.4   18.9   (1.0)
            Long-Term Incentive Plan charge  42.7   26.1   7.9 
            Noncash amortization of terminated interest rate hedging instruments  1.5   1.6   1.5 
            (Gain)/loss on foreign currency revaluation  4.1   2.1   (5.0)
            Net cash paid for terminated interest rate hedging instruments  (2.4)  (0.9)  (1.5)
            Equity earnings in unconsolidated entities  (7.7)  (1.8)  (0.5)
            Changes in assets and liabilities, net of acquisitions:            
            Trade accounts receivable and other  (729.0)  (298.4)  (28.7)
            Inventory  (324.5)  (425.1)  (398.7)
            Accounts payable and other current liabilities  356.7   427.8   327.5 
            Inventory in third party assets  (0.2)  —   (7.2)
            Due to related parties  (6.0)  (27.5)  5.9 
                         
            Net cash provided by (used in) operating activities  (275.3)  24.1   104.0 
                         
            CASH FLOWS FROM INVESTING ACTIVITIES
            		            
            Cash paid in connection with acquisitions, net of $20.0 cash acquired from acquisitions (Note 3)  (1,263.9)  (30.0)  (535.3)
            Additions to property and equipment  (341.0)  (164.1)  (116.9)
            Investment in unconsolidated entities  (45.9)  (112.5)  — 
            Cash paid for linefill in assets owned  (4.6)  —   (2.0)
            Proceeds from sales of assets  4.4   9.4   3.0 
                         
            Net cash used in investing activities  (1,651.0)  (297.2)  (651.2)
                         
            CASH FLOWS FROM FINANCING ACTIVITIES
            		            
            Net borrowings/(repayments) on long-term revolving credit facility  (298.5)  (143.7)  64.9 
            Net borrowings on working capital revolving credit facility  2.8   67.2   62.9 
            Net borrowings/(repayments) on short-term letter of credit and hedged inventory facility  616.0   138.9   (20.1)
            Proceeds from the issuance of senior notes  1,242.8   149.3   348.1 
            Net proceeds from the issuance of common units (Note 5)  642.8   264.2   262.1 
            Distributions paid to unitholders and general partner (Note 5)  (262.6)  (197.0)  (158.4)
            Other financing activities  (16.3)  (8.3)  (5.0)
                         
            Net cash provided by financing activities  1,927.0   270.6   554.5 
                         
            Effect of translation adjustment on cash  1.0   (0.9)  1.6 
            Net increase (decrease) in cash and cash equivalents  1.7   (3.4)  8.9 
            Cash and cash equivalents, beginning of period  9.6   13.0   4.1 
                         
            Cash and cash equivalents, end of period $11.3  $9.6  $13.0 
                         
            Supplemental Cash Flow Formation:
            		            
            Cash paid for interest, net of amounts capitalized $122.3  $80.4  $40.8 
            Non-cash investing and financing transactions (all items are in connection with the Pacific acquisition):            
            Issuance of common units $1,001.6  $—  $— 
            Assumption of senior notes  433.1   —   — 
            Assumption of property, plant and equipment  1,411.7   —   — 
            Assumption of intangible assets  72.3   —   — 
            The accompanying notes are an integral part of these consolidated financial statements.


            F-7



            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

            CONSOLIDATED STATEMENTSTATEMENTS OF CHANGES IN PARTNERS'PARTNERS’ CAPITAL

            (in thousands)

             
            		 Common
            Unitholders
            		 Class B Common Unitholders
            		 Subordinated
            Unitholders
            		 General
            Partner
            		 Total
            Partners'
            Capital
            		 
             
            		 Units
            		 Amount
            		 Units
            		 Amount
            		 Units
            		 Amount
            		 Amount
            		 Amount
            		 
            Balance at December 31, 2000 23,049 $217,073 1,307 $21,042 10,030 $(27,316)$3,200 $213,999 
            Issuance of units 8,867  222,032 —  — —  —  5,517  227,549 
            Noncash compensation expense —  — —  — —  —  5,741  5,741 
            Net income —  29,436 —  1,476 —  11,327  1,940  44,179 
            Distributions —  (51,271)—  (2,549)—  (19,558) (2,551) (75,929)
            Other comprehensive loss —  (8,708)—  (435)—  (3,344) (255) (12,742)
              
            		 
            		 
            		 
            		 
            		 
            		 
            		 
            		 

            Balance at December 31, 2001
             
            31,916
             
             
            408,562
             
            1,307
             
             
            19,534
             
            10,030
             
             
            (38,891
            )
             
            13,592
             
             
            402,797
             
            Issuance of units 6,325  142,013 —  — —  —  3,033  145,046 
            Net income —  45,857 —  1,736 —  13,319  4,380  65,292 
            Distributions —  (70,821)—  (2,762)—  (21,188) (5,070) (99,841)
            Other comprehensive loss —  (1,183)—  (45)—  (343) (113) (1,684)
              
            		 
            		 
            		 
            		 
            		 
            		 
            		 
            		 

            Balance at December 31, 2002
             
            38,241
             
             
            524,428
             
            1,307
             
             
            18,463
             
            10,030
             
             
            (47,103
            )
             
            15,822
             
             
            511,610
             

            Issuance of units
             
            8,736
             
             
            245,093
             
            —
             
             
            —
             
            —
             
             
            —
             
             
            5,237
             
             
            250,330
             
            Issuance of units under LTIP 18  555 —  — —  —  11  566 
            Net income —  41,278 —  1,370 —  10,825  5,975  59,448 
            Conversion of 25% of subordinated units 2,507  (9,823)—  — (2,507) 9,823  —  — 
            Distributions —  (89,801)—  (2,860)—  (21,939) (7,222) (121,822)
            Other comprehensive income —  32,343 —  1,073 —  8,481  4,698  46,595 
              
            		 
            		 
            		 
            		 
            		 
            		 
            		 
            		 

            Balance at December 31, 2003
             
            49,502
             
            $
            744,073
             
            1,307
             
            $
            18,046
             
            7,523
             
            $
            (39,913
            )
            $
            24,521
             
            $
            746,727
             
              
            		 
            		 
            		 
            		 
            		 
            		 
            		 
            		 

                                                         
                    Class B  Class C        General
            		     Partners’
            		 
              Common Units  Common Units  Common Units  Subordinated Units  Partner
            		  Total
            		  Capital 
              Units  Amount  Units  Amount  Units  Amount  Units  Amount  Amount  Units  Amount 
              (In millions) 
             
            Balance at December 31, 2003  49.5  $744.1   1.3  $18.0    —  $ —   7.5  $(39.9) $24.5   58.3  $746.7 
                                                         
            Net income  —   111.1   —   2.5   —   4.2   —   1.5   10.7   —   130.0 
            Distributions  —   (134.2)  —   (3.0)  —   (5.7)  —   (4.2)  (11.3)  —   (158.4)
            Issuance of common units  5.0   157.5   —   —   —   —   —   —   3.4   5.0   160.9 
            Issuance of common units under LTIP  0.4   11.8   —   —   —   —   —   —   0.2   0.4   12.0 
            Issuance of units for acquisition contingent consideration  0.4   13.1   —   —   —   —   —   —   0.3   0.4   13.4 
            Private placement of Class C common units  —   —   —   —   3.2   98.8   —   —   2.1   3.2   100.9 
            Other comprehensive income  —   59.9   —   1.3   —   3.1   —   (0.9)  1.3   —   64.7 
            Conversion of subordinated units  7.5   (43.5)  —   —   —   —   (7.5)  43.5   —   —   — 
                                                         
            Balance at December 31, 2004  62.8  $919.8   1.3  $18.8   3.2  $100.4    —  $ —  $31.2   67.3  $1,070.2 
                                                         
            Net income  —   196.9   —   0.5   —   1.4   —   —   19.0   —   217.8 
            Distributions  —   (175.6)  —   (0.8)  —   (2.0)  —   —   (18.6)  —   (197.0)
            Issuance of common units  6.5   258.7   —   —   —   —   —   —   5.5   6.5   264.2 
            Issuance of common units under LTIP  —   1.9   —   —   —   —   —   —   —   —   1.9 
            Conversion of Class B Units  1.3   18.3   (1.3)  (18.3)  —   —   —   —   —   —   — 
            Conversion of Class C Units  3.2   99.3   —   —   (3.2)  (99.3)  —   —   —   —   — 
            Other Comprehensive loss  —   (25.2)  —   (0.2)  —   (0.5)  —   —   (0.5)  —   (26.4)
                                                         
            Balance at December 31, 2005  73.8  $1,294.1    —  $ —    —  $ —    —  $ —  $36.6   73.8  $1,330.7 
                                                         
            Net income  —   246.9   —   —   —   —   —   —   38.2   —   285.1 
            Distributions  —   (224.9)  —   —   —   —   —   —   (37.7)  —   (262.6)
            Issuance of common units in connection with Pacific acquisition  22.2   1,001.6   —   —   —   —   —   —   21.6   22.2   1,023.2 
            Issuance of common units  13.4   608.8   —   —   —   —   —   —   12.4   13.4   621.2 
            Other Comprehensive loss  —   (20.4)  —   —   —   —   —   —   (0.4)  —   (20.8)
                                                         
            Balance at December 31, 2006  109.4  $2,906.1    —  $ —    —  $ —    —  $ —  $70.7   109.4  $2,976.8 
                                                         
            The accompanying notes are an integral part of these consolidated financial statements.



            F-8


            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES

            CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

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

            		 
            Net income $59,448 $65,292 $44,179 
            Other comprehensive income (loss)  46,595  (1,684) (12,742)
              
            		 
            		 
            		 
            Comprehensive income $106,043 $63,608 $31,437 
              
            		 
            		 
            		 


            CONSOLIDATED STATEMENT OF CHANGES IN ACCUMULATED
            OTHER COMPREHENSIVE INCOME (LOSS)

             
            		 Net Deferred
            Loss on
            Derivative
            Instruments
            		 Currency
            Translation
            Adjustments
            		 Total
            		 
             
            		 (in thousands)

            		 
            Balance at December 31, 2000 $— $— $— 
            Cumulative effect of accounting change  (8,337) —  (8,337)
            Reclassification adjustments for settled contracts  (2,526) —  (2,526)
            Changes in fair value of outstanding hedge positions  6,123  —  6,123 
            Currency translation adjustment  —  (8,002) (8,002)
              
            		 
            		 
            		 
            Balance at December 31, 2001  (4,740) (8,002) (12,742)
            Reclassification adjustments for settled contracts  797  —  797 
            Changes in fair value of outstanding hedge positions  (4,264) —  (4,264)
            Currency translation adjustment  —  1,783  1,783 
              
            		 
            		 
            		 
             2002 Activity  (3,467) 1,783  (1,684)
              
            		 
            		 
            		 
            Balance at December 31, 2002  (8,207) (6,219) (14,426)
            Reclassification adjustments for settled contracts  (28,151) —  (28,151)
            Changes in fair value of outstanding hedge positions  28,666  —  28,666 
            Currency translation adjustment  —  46,080  46,080 
              
            		 
            		 
            		 
             2003 Activity  515  46,080  46,595 
              
            		 
            		 
            		 
            Balance at December 31, 2003 $(7,692)$39,861 $32,169 
              
            		 
            		 
            		 

                         
              Twelve Months Ended December 31, 
              2006  2005  2004 
              (In millions) 
             
            Net income $285.1  $217.8  $130.0 
            Other comprehensive income/(loss)  (20.8)  (26.4)  64.7 
                         
            Comprehensive income $264.3  $191.4  $194.7 
                         
            The accompanying notes are an integral part of these consolidated financial statements.



            F-9

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            CONSOLIDATED STATEMENTS OF CHANGES IN ACCUMULATED
            OTHER COMPREHENSIVE INCOME
                         
              Net Deferred
            		       
              Gain/(Loss) on
            		  Currency
            		    
              Derivative
            		  Translation
            		    
              Instruments  Adjustments  Total 
              (In millions) 
             
            Balance at December 31, 2003 $(7.7) $39.9  $32.2 
            Reclassification adjustments for settled contracts  13.2   —   13.2 
            Changes in fair value of outstanding hedge positions  20.4   —   20.4 
            Currency translation adjustment  —   31.1   31.1 
                         
            2004 Activity  33.6   31.1   64.7 
                         
            Balance at December 31, 2004 $25.9  $71.0  $96.9 
                         
            Reclassification adjustments for settled contracts  117.4   —   117.4 
            Changes in fair value of outstanding hedge positions  (159.9)  —   (159.9)
            Currency translation adjustment  —   16.1   16.1 
                         
            2005 Activity  (42.5)  16.1   (26.4)
                         
            Balance at December 31, 2005 $(16.6) $87.1  $70.5 
                         
            Reclassification adjustments for settled contracts  (145.3)  —   (145.3)
            Changes in fair value of outstanding hedge positions  142.1   —   142.1 
            Currency translation adjustment  —   (17.6)  (17.6)
                         
            2006 Activity  (3.2)  (17.6)  (20.8)
                         
            Balance at December 31, 2006 $(19.8) $69.5  $49.7 
                         
            The accompanying notes are an integral part of these consolidated financial statements.


            F-10

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
            Note 1—1 — Organization and Basis of Presentation

            Organization

            Plains All American Pipeline, L.P. is a publicly traded Delaware limited partnership (the "Partnership")formed in September 1998. Our operations are conducted directly and indirectly through our primary operating subsidiaries. As used in thisForm 10-K, the terms “Partnership,” “Plains,” “we,” “us,” “our,” “ours” and similar terms refer to Plains All American Pipeline, L.P. and its subsidiaries, unless the context indicates otherwise.
            We are engaged in interstatethe transportation, storage, terminalling and intrastatemarketing of crude oil, transportation,refined products and crude oil gathering, marketing, terminalling and storage, as well as the marketing and storage of liquefied petroleum gas and other natural gas-related petroleum products. We refer to liquifiedliquefied petroleum gas and other natural gas related petroleum products collectively as "LPG". We were formed“LPG.” Through our 50% equity ownership in September 1998 to acquirePAA/Vulcan Gas Storage, LLC (“PAA/Vulcan”), we develop and operate natural gas storage facilities. Prior to the midstream crude oilfourth quarter of 2006, we managed our operations through two segments. Due to our growth, especially in the facilities portion of our business (most notably in conjunction with the Pacific acquisition), we have revised the manner in which we internally evaluate our segment performance and assets of Plains Resources Inc. and its wholly-owned subsidiaries ("Plains Resources") as a separate, publicly traded master limited partnership. We completeddecide how to allocate resources to our initial public offering in November 1998.segments. As a result, of subsequent equity offeringswe now manage our operations through three operating segments: (i) Transportation, (ii) Facilities, 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 Plains Resources' limited partner units (the "General Partner Transition"), Plains Resources' overall effective ownership in us was reduced to approximately 22%.

                    As a result of the 2001 transaction, our(iii) Marketing.

            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’s general partner. Plains All American GP LLC manages our operations and activities and employs our domestic officers and personnel, who devote 100%personnel. Our Canadian officers and employees are employed by our subsidiary PMC (Nova Scotia) Company, the general partner of their efforts to the management of the Partnership.Plains Marketing Canada, L.P. Unless the context otherwise requires, we use the term "general partner"“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 7seven owners with the largest interest, 44%, held by Plains Resources. We use the phrase "former general partner"interests ranging from 54.3% to refer to the subsidiary of Plains Resources that formerly held the general partner interest.

                    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., and are concentrated in Texas, Oklahoma, California, Louisiana and the Canadian provinces of Alberta and Saskatchewan.

            1.2%.

            Basis of Consolidation and Presentation

            The accompanying financial statements and related notes present our consolidated financial position as of December 31, 20032006 and 2002,2005, and the consolidated results of our operations, cash flows, changes in partners'partners’ capital, and comprehensive income (loss) for the years ended December 31, 2003, 2002 and 2001, and changes in accumulated other comprehensive income for the years ended December 31, 20032006, 2005 and 2002.2004. All significant intercompany transactions have been eliminated. Certain reclassifications werehave been made to prior periodsthe previous years to conform to the 2006 presentation of the financial statements. These reclassifications do not affect net income. The accompanying consolidated financial statements of PAA include PAA and all of its wholly owned subsidiaries. Investments in 50% or less owned entities over which we have significant influence but not control are accounted for by the equity method. We evaluate our equity investments for impairment in accordance with APB 18:The Equity Method of Accounting for Investments in Common Stock.  An impairment of an equity investment results when factors indicate that the investment’s fair value is less than its carrying value and the reduction in value is other than temporary in nature.
            Changes in Accounting Principle
            Stock-Based Compensation
            In December 2004, SFAS 123(R) was issued, which amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost resulting from such share-based payment transactions be recognized in the financial statements at fair value. Following our general partner’s adoption of Emerging Issues Task Force IssueNo. 04-05, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” we are now part of the same consolidated group and thus SFAS 123(R) is applicable to our general partner’s long-term incentive plan. We adopted SFAS 123(R) on January 1, 2006 under the modified prospective transition method, as defined in


            F-11

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            SFAS 123(R), and recognized a cumulative effect of change in accounting principle of approximately $6 million. The cumulative effect adjustment represents a decrease to our LTIPlife-to-date accrued expense and related liability under our previous cash-plan, probability-based accounting model and adjusts our aggregate liability to the appropriate fair-value based liability as calculated under a SFAS 123(R) methodology. Our LTIPs are administered by our general partner. We are required to reimburse all costs incurred by our general partner related to LTIP settlements. Our LTIP awards are classified as liabilities under SFAS 123(R) as the awards are primarily paid in cash. Under the modified prospective transition method, we are not required to adjust our prior period financial statements for this change in accounting principle.
            Linefill
            During the second quarter of 2004, we changed our method of accounting for pipeline linefill in third-party assets. Historically, we 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 did not include linefill barrels in the same average costing calculation as our operating inventory, but instead carried linefill at historical cost. Following this change in accounting principle, the linefill in third-party assets that we historically classified as a portion of Pipeline Linefill on the face of the balance sheet (a long-term asset) and carried at historical cost, is 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, presentation.

            we 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 on the consolidated balance sheet.

            This change in accounting principle was effective January 1, 2004 and is reflected as a cumulative change in our consolidated statement of operations for the year ended December 31, 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 in Third-Party Assets of $28.9 million.
            Note 2—2 — Summary of Significant Accounting Policies

            Use of Estimates

            The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates we make include: (i) accruals related to purchases and sales,(ii) mark-to-market estimates pursuant to Statement of Financial Accounting Standards ("SFAS"(“SFAS”) No. 133 "Accounting“Accounting For Derivative Instruments and Hedging Activities",Activities,” as amended (“SFAS 133”), (iii) contingent liability accruals, (iv) accruals related to our Long-Term Incentive Plan (the "LTIP") and (v) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets.assets, (v) accruals related to our Long-Term Incentive Plans, (vi) property, plant, and equipment and depreciation expense, and (vii) accruals related to deferred tax assets, valuation allowances and tax liabilities. Although we believe these estimates are reasonable, actual results could differ from these estimates.



            Revenue Recognition

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

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


            F-12

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            activities primarily consist of the purchase and sale of crude oil shipped on our San Joaquin Valley system using barrel exchanges and buy/sell arrangements. Revenues associated with these activities are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. All of our pipeline margin activities revenues are based on actual volumes and prices.
            Facilities Segment Revenues.  Storage and terminalling revenues (which are included within Other Revenues on our Consolidated Statements of Operations) consist of (i) storage fees from actual storage used on amonth-to-month basis; (ii) storage fees resulting from short-term and long-term contracts for committed space that may or may not be utilized by the customer in a given month; and (iii) terminal throughput charges to pump to connecting carriers. Revenues on storage are recognized ratably over the term of the contract. Terminal throughput charges are recognized as the crude oil, LPG or refined product exits the terminal and is delivered to the connecting carrier or third-party terminal. Any throughput volumes in transit at the end of a given month are treated as third party inventory and do not incur storage fees. All terminalling and storage revenues are based on actual volumes and rates.
            Marketing Segment Revenues.  Revenues from sales of crude oil, LPG and other products are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil and LPG consist of outright sales contracts and buy/sell arrangements as well as barrel exchanges. In September 2005, the Emerging Issues Task Force (“EITF”) issued IssueNo. 04-13 (“EITF04-13”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The EITF concluded that inventory purchases and sales transactions with the same counterparty should be combined for accounting purposes if they were entered into in contemplation of each other. The EITF provided indicators to be considered for purposes of determining whether such transactions are entered into in contemplation of each other. Guidance was also provided on the circumstances under which nonmonetary exchanges of inventory within the same line of business should be recognized at fair value. EITF04-13 became effective in reporting periods beginning after March 15, 2006.
            We adopted EITF04-13 on April 1, 2006.  The adoption of EITF04-13 resulted in inventory purchases and sales under buy/sell transactions, which historically would have been recorded gross as purchases and sales, to be treated as inventory exchanges in our consolidated statement of operations. In conformity with EITF04-13, prior periods are not affected, although we have parenthetically disclosed prior period buy/sell transactions in our consolidated statements of operations. The treatment of buy/sell transactions under EITF04-13 reduces both revenues and purchases on our income statement but does not impact our financial position, net income, or liquidity.
            Purchases and Related Costs

            Purchases and related costs include: (i) the cost of crude oil and LPG purchased;purchased in outright purchases as well as buy/sell arrangements prior to the adoption of EITF 04-13; (ii) third partythird-party transportation and storage, whether by pipeline, truck or barge; (iii) interest cost attributable to borrowings for inventory stored in a contango market; (iv) performance related bonus accruals; and (iii)(v) expenses to issueof issuing letters of credit to support these purchases. These purchases are accrued at the time title transfers to us which occurs upon receipt of the product.

            us.

            Operating Expenses and General and Administrative Expenses

            Operating expenses consist of various field and pipeline operating expenses including fuel and power costs, telecommunications, laborpayroll and benefit costs for truck drivers and pipeline field personnel, maintenance costs, regulatory compliance, environmental remediation, insurance, vehicle leases, and property taxes. General and administrative expenses consist primarily of payroll and benefit costs, certain information system and legal costs, office rent, contract and consultant costs, and audit and tax fees.


            F-13

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            Foreign Currency Transactions
            Assets and liabilities of subsidiaries with a functional currency other than the U.S. Dollar are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income in partners’ capital. Gains and losses from foreign currency transactions (transactions denominated in a currency other than the entity’s functional currency) are included in the consolidated statement of operations. The foreign currency transactions resulted in a loss of approximately $4.1 million, a loss of approximately $2.1 million, and a gain of approximately $5.0 million for the years ended December 31, 2006, 2005, and 2004, respectively.
            Cash and Cash Equivalents

            Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and at times maytypically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that any possiblethe credit risk is minimal.

            Accounts Receivable

            Our accounts receivable are primarily from purchasers and shippers of crude oil. There were no amounts due from related parties at December 31, 2003 or 2002.oil and, to a lesser extent, purchasers of LPG. The majority of our accounts



            receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities, in many cases involving complex exchanges of crude oil volumes. 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.

                    Accountscredit, advance cash payments or “parental” guarantees. At December 31, 2006 and 2005, we had received approximately $28.3 million and $52.5 million, respectively, of advance cash payments and prepayments from third parties to mitigate credit risk. In addition, we enter into netting arrangements with our counterparties. These arrangements cover a significant part of our transactions and also serve to mitigate credit risk.

            We review all outstanding accounts receivable included inbalances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the consolidated balance sheets are reflectedreserve until substantially all collection efforts have been exhausted. At December 31, 2006 and 2005, substantially all of our net ofaccounts receivable classified as current were less than 60 days past their scheduled invoice date, and our allowance for doubtful accounts. We routinely reviewaccounts receivable (the entire balance of which is classified as current) totaled $0.7 million and $0.8 million, respectively. Although we consider our receivable balances to identify past due amounts and analyze the reasons such amounts have not been collected. In many instances, such delays involve billing delays and discrepancies or disputes as to the appropriate price, volumes or quality of crude oil delivered or exchanged. We also attempt to monitor changes in the creditworthiness of our customers as a result of developments related to each customer, the industry as a whole and the general economy. Based on these analyses as well as our historical experience and the facts and circumstances surrounding certain aged balances, we have established an allowance for doubtful trade accounts receivable and consider this reserve adequate; however,to be adequate, there is no assurance that actual amounts will not vary significantly from estimated amounts. The discovery of previously unknown facts or adverse developments affecting one of our counterparties or the industry as a whole could adversely impact our results of operations.

                    At December 31, 2003 and 2002, approximately 99% of net accounts receivable classified as current were less than 60 days past scheduled invoice date, and our allowance for doubtful accounts receivable classified as current totaled $0.2 million and $3.1 million, respectively. We consider these reserves adequate. At December 31, 2003 we had no accounts receivable balances or allowance for doubtful accounts classified as long-term. At December 31, 2002, approximately $11.5 million of accounts receivable ($6.5 million, net of a $5.0 million allowance) was classified as long-term. Following is a reconciliation of the changes in our allowance for doubtful accounts balances (in millions):

                           
             December 31,   

            		 December 31,
            		 2006 2005 2004   

            		 2003
            		 2002
            		 2001
            Balance at beginning of year $8.1 $8.0 $5.0 $0.8  $0.6  $0.2     
            Applied to accounts receivable balances (8.3) — —  (0.3)  (0.7)  —     
            Charged to expense 0.4 0.1 3.0  0.2   0.9   0.4     
             
            		 
            		 
            		       
            Balance at end of year $0.2 $8.1 $8.0 $0.7  $0.8  $0.6     
             
            		 
            		 
            		       
            Inventory and Pipeline Linefill

            Inventory primarily consists of crude oil, refined products and LPG in pipelines, storage tanks and rail cars whichthat is valued at the lower of cost or market, with cost determined using an average cost method. InDuring 2006, we recorded a $5.9 million noncash charge related to the writedown of our crude oil and LPG inventory due to declines in oil prices during the third and fourth quarters of 2006. During the fourth quarter of 2001, the Partnership2004, we recorded a $5.0


            F-14

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            $2.0 million noncash charge related to the writedown of operating crude oil inventory to reflect prices at December 31, 2001. During 2001, the price of crude oil traded on the NYMEX averaged $25.98 per barrel. At December 31, 2001, the NYMEX crude oil price was approximately 24% lower, or $19.84 per barrel.our LPG inventory. There was no writedown of operating crude oilsuch charge in 2005. Linefill and minimum working inventory requirements in assets we own are recorded at December 31, 2003 or 2002, as the market priceshistorical cost and consist of crude oil and LPG were higher thanused to pack the pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location, as well as the minimum amount of crude oil necessary to operate our storage and terminalling facilities.
            Minimum working inventory requirements in third-party assets are included in Inventory (a current asset) in determining the average cost per barrel. of operating inventory and applying the lower of cost or market analysis. At the end of each period, we reclassify the inventory in third party assets not expected to be liquidated within the succeeding twelve months out of Inventory, at average cost, and into Inventory in Third-Party Assets (a long-term asset), which is reflected as a separate line item within other assets on the consolidated balance sheet.
            At December 31, 20032006 and 2002,2005, inventory and linefill consisted of (in millions):

             
            		 December 31,
             
            		 2003
            		 2002
            Crude oil $50.6 $53.5
            LPG  53.8  28.3
            Other  1.6  —
              
            		 
              $106.0 $81.8
              
            		 
            of:
                                     
              December 31, 2006  December 31, 2005 
                    Dollar/
            		        Dollar/
            		 
              Barrels  Dollars  barrel  Barrels  Dollars  barrel 
              (Barrels in thousands and dollars in millions) 
             
            Inventory(1)
            		                        
            Crude oil  18,331  $1,029.1  $56.14   13,887  $755.7  $54.42 
            LPG  5,818   250.7  $43.09   3,649   149.0  $40.83 
            Refined Products  81   3.8  $46.91   —   —   N/A 
            Parts and supplies  N/A   6.4   N/A   N/A   5.6   N/A 
                                     
            Inventory subtotal  24,230   1,290.0       17,536   910.3     
                                     
            Inventory in third-party assets(1)
            		                        
            Crude oil  1,212   62.5  $51.57   1,248   58.6  $46.96 
            LPG  318   13.2  $41.51   318   12.9  $40.57 
                                     
            Inventory in third-party assets subtotal  1,530   75.7       1,566   71.5     
                                     
            Linefill in owned assets
            		                        
            Crude oil  7,831   264.4  $33.76   6,207   179.3  $28.89 
            LPG  31   1.1  $35.48   27   0.9  $33.33 
                                     
            Linefill in owned assets subtotal  7,862   265.5       6,234   180.2     
                                     
            Total
            		  33,622  $1,631.2       25,336  $1,162.0     
                                     
            (1)Includes the impact of inventory hedges on a portion of our volumes.


            F-15

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            Property and Equipment and Pipeline Linefillequipment

            Property and equipment, net is stated at cost and consisted of the following (in millions):

            following:
                      
             Estimated Useful
            		 December 31, 
             Lives (Years) 2006 2005 

            		 December 31,
            		    (In millions) 

            		 2003
            		 2002
            		 
            Crude oil pipelines and facilities $1,114.5 $909.3  30 - 40 $3,484.3  $1,739.5 
            Crude oil and LPG storage and terminal facilities 100.8 82.4  30 - 40  456.1   214.6 
            Trucking equipment and other 43.8 30.0  5 - 15  211.6   137.1 
            Office property and equipment 13.5 8.6  3 - 5  38.1   24.9 
             
            		 
            		      
             1,272.6 1,030.3     4,190.1   2,116.1 
            Less accumulated depreciation (121.6) (77.5)    (348.1)  (258.9)
             
            		 
            		      
            Property and equipment, net   $3,842.0  $1,857.2 
             $1,151.0 $952.8      
             
            		 
            		 
            Depreciation expense for each of the three years in the period ended December 31, 2003,2006 was $42.4$91.3 million, $30.2$79.2 million and $21.6$64.8 million, respectively. Our policy is to depreciate property and equipment over estimated useful lives as follows:

              •
              crude oil pipelines and facilities—30 to 40 years;

              •
              crude oil and LPG storage and terminal facilities—30 to 40 years;

              •
              trucking equipment and other—5 to 15 years; and

              •
              office property and equipment—3 to 5 years

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

            Also, gains/losses on sales of assets and asset impairments are included as a component of depreciation and amortization in the consolidated statements of operations.

            In accordance with our capitalization policy, costs associated with acquisitions and improvements that expand our existing capacity, including related interest costs, which expand our existing capacity are capitalized. For the years ended December 31, 2003, 20022006, 2005 and 2001,2004, capitalized interest was $0.5$6.0 million, $0.8$1.8 million and $0.2$0.5 million, respectively. In addition, costs required either to maintain the existing operating capacity of partially or fully depreciated assets or to extend their useful lives are capitalized and classified as maintenance capital. 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.

                    Linefill

            Equity Method of Accounting
            Our investments in PAA/Vulcan, Frontier Pipeline Company (“Frontier”), Settoon Towing, LLC (“Settoon Towing”) and minimum working inventory requirementsButte Pipe Line Company (“Butte”) are recorded at loweraccounted for under the equity method of costaccounting. Our ownership interests in PAA/Vulcan, Frontier, Settoon Towing and Butte are 50%, 22%, 50% and 22%, respectively. We do not consolidate any part of the assets or market and consistsliabilities of crude oil and LPG used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location as well as minimum crude oil necessary to operate our storage and terminalling facilities. At December 31, 2003, we had approximately 4.6 million barrelsequity investees. Our share of crude oil and 7.7 million gallons of LPG used to maintain our minimum linefill and working inventory requirements. Proceeds from the sale and repurchase of pipeline linefill arenet income or loss is reflected as one line item on the income statement and will increase or decrease, as applicable, the carrying value of our investments on the balance sheet. Distributions to the Partnership will reduce the carrying value of our investments and will be reflected on our cash flows from operating activities in the accompanying consolidated statements of cash flows.

            flow statement.


            Asset Retirement Obligation

                    In June 2001, the FASB issued

            We account for asset retirement obligations under SFAS No. 143 "Asset“Accounting for Asset Retirement Obligations."” SFAS 143 establishes accounting requirements for retirement obligations associated with


            F-16

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            tangible long-lived assets, including (1) the time of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Effective January 1, 2003, we adopted SFAS 143, as required. Determination of the amounts to be recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rate. The majority
            Some of our assets, primarily related to our pipeline operationstransportation segment, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. The timing of the obligations is determined relative to the date on which the asset is abandoned. However,Many of our pipelines are trunk and interstate systems that transport crude oil. The pipelines with indeterminate settlement dates have been in existence for many years and with regular maintenance will continue to be in service for many years to come. Also, it is not possible to predict when demands for this transportation will cease and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations cannot be reasonably estimated, as the settlement dates are indeterminate. We will record such asset retirement obligationsfor these assets in the period in which we cansufficient information becomes available for us to reasonably determine the settlement dates. The adoptionA small portion of this statement didour contractual or regulatory obligations are related to assets that are inactive or that we plan to take out of service and although the ultimate timing and costs to settle these obligations are not known with certainty, we can reasonably estimate the obligation. We have a material impact on our financial position, resultsestimated that the fair value of operations or cash flows.

            these obligations is approximately $4.7 million and $4.6 million at December 31, 2006 and 2005, respectively.

            Impairment of Long-Lived Assets

            Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 "Accounting“Accounting for the Impairment or Disposal of Long-Lived Assets,"” as amended. Under SFAS 144, ana long-lived asset shall beis tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. Impairments were not material in 2006 and 2005. In 2004, we recognized a charge of approximately $2.0 million associated with taking our pipeline in the Illinois Basin out of service. The impairments, which were predominantly related to assets that will be taken out of service, are included as a component of depreciation and amortization in the consolidated statements of operations. These assets did not support spending the capital necessary to continue service and we utilized other assets to handle these activities.
            We adopted SFAS 144 on January 1, 2002,periodically evaluate property, plant and there have been noequipment for impairment when events or circumstances indicatingindicate that the carrying value of any of ourthese assets may not be recoverable.

            Other Assets

                    Other assets, net consist The evaluation is highly dependent on the underlying assumptions of the following (in millions):

             
            		 December 31,
            		 
             
            		 2003
            		 2002
            		 
            Goodwill $39.4 $12.9 
            Deposit on Capline Acquisition  15.8  — 
            Debt issue costs  12.1  21.6 
            Investment in affiliate  7.8  8.0 
            Long term receivable, net  —  6.5 
            Fair value of derivative instruments  5.9  2.6 
            Intangible assets (contracts)  2.6  2.4 
            Other  7.1  2.6 
              
            		 
            		 
               90.7  56.6 
            Less accumulated amortization  (1.7) (8.3)
              
            		 
            		 
              $89.0 $48.3 
              
            		 
            		 

                    Goodwill is recorded as the amount of the purchase price in excess ofrelated cash flows. We consider the fair value estimate used to calculate impairment of certain assets purchased. At December 31, 2003,property, plant and equipment a critical accounting estimate. In determining the existence of an impairment in carrying value, we recorded additional consideration related to the deferred



            portionmake a number of the purchase price in the CANPET acquisition (See Note 3). The entire amount of this consideration was recordedsubjective assumptions as additional goodwill. to:

            • whether there is an indication of impairment;
            • the grouping of assets;
            • the intention of “holding” versus “selling” an asset;


            F-17

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            • the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and
            • if an impairment exists, the fair value of the asset or asset group.
            Goodwill and Other Intangible Assets
            In accordance with SFAS No. 142, "Goodwill“Goodwill and Other Intangible Assets," which we adopted January 1, 2002,” we test goodwill and other intangible assets periodicallyat least annually (on June 30) to determine whether an impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. Pursuant to SFAS 142, a reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are one level below our operating segments. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is considered not impaired. Fair value is assessed based on multiples of earnings or revenue. An impairment loss is recognized for intangibles if the carrying amount of an intangible asset is not recoverable and its carrying amount exceeds its fair value. AsSince adoption of SFAS 142, we have not recognized any impairment of goodwill.
            The table below reflects our changes in goodwill:
                             
              Transportation  Facilities  Marketing  Total 
              (In millions) 
             
            Balance at December 31, 2004 $—  $0.4  $47.0  $47.4 
                             
            Balance at December 31, 2005 $—  $0.4  $47.0  $47.4 
                             
            2006 Additions                
            Pacific(1)  393.0   190.2   260.0   843.2 
            Andrews  5.9   58.4   6.0   70.3 
            SemCrude  —   —   62.8   62.8 
            Other  —   —   2.5   2.5 
                             
            Balance at December 31, 2006 $398.9  $249.0  $378.3  $1,026.2 
                             
            (1)The purchase price allocation related to the Pacific acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired.
            Intangible assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. Our intangible assets consist of the following:
                                         
              Estimated Useful
            		       
              Lives (Years)  December 31, 2006  December 31, 2005 
                 (In millions) 
                    Accumulated
            		        Accumulated
            		    
                 Cost  amortization  Net  Cost  amortization  Net 
             
            Customer contracts  5-17  $82.3  $(5.4) $76.9  $2.8  $(1.1) $1.7 
            Emission reduction credits  n/a   33.3   —   33.3   —   —   — 
            Environmental permits  2   7.9   (0.5)  7.4   —   —   — 
                                         
                  $123.5  $(5.9) $117.6  $2.8  $(1.1) $1.7 
                                         
            Our amortization expense for finite-lived intangible assets for the years ended December 31, 2003, no impairment has occurred.2006, 2005 and 2004 was $4.8 million, $0.3 million and $0.3, respectively.


            F-18

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):
                 
            2007 $10.7 
            2008 $10.0 
            2009 $6.6 
            2010 $6.6 
            2011 $5.6 
            Other assets, net
            Other assets, net of accumulated amortization consist of the following:
                     
              December 31, 
              2006  2005 
              (In millions) 
             
            Debt issue costs $29.3  $17.4 
            Fair value of derivative instruments  9.1   5.5 
            Intangible assets(1)  123.5   2.8 
            Other  17.9   18.5 
                     
               179.8   44.2 
            Less accumulated amortization  (14.9)  (7.1)
                     
              $164.9  $37.1 
                     
            (1)The majority of the increase in 2006 relates to acquisitions. See the table above and Note 3.
            Costs incurred in connection with the issuance of long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the "effective interest"“effective interest” method of amortization. During the fourth quarter of 2003, we replaced our senior secured credit facilities with new senior unsecured credit facilities and we completed the sale of $250 million of 5.625% senior notes (See Note 6). We capitalized approximately $5.1 million of costs associated with those transactions. Also, in conjunction with the credit facility refinancing, we incurred a non-cash charge of approximately $3.3 million attributable to a loss on the early extinguishment of debt (included in Interest income and other, net on the Consolidated Statement of Operations). The loss consists of unamortized debt issue costs written off as a result of the completion of the new credit facility. In addition, we wrote off approximately $11.3 million of fullyFully amortized debt issue costs and the related accumulated amortization are written off in conjunction with the refinancing or termination of the applicable debt arrangement. We capitalized debt issue costs of approximately $13.2 million, $3.3 million and $5.9 million in 2006, 2005 and 2004, respectively. In addition, during 2006 we wrote off approximately $1.4 million of fully amortized costs and the related accumulated amortization.

            During 2006, 2005 and 2004, we wrote off unamortized costs totaling $0, $1.4 million and $0.7 million, respectively.

            Amortization ofexpense related to other assets (including finite-lived intangible assets) for each of the three years in the period ended December 31, 2003,2006, was $4.4$9.1 million, $4.3 million and $3.9 million, and $2.7 million, respectively.

            Environmental Matters

                    We expense or capitalize, as appropriate, environmental expenditures. We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation.

            We record environmental liabilities when environmental assessmentsand/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We also record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.
            We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. See Note 13.


            F-19

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            Income and Other Taxes

                    Except as noted below, no

            No provision for U.S. federal or Canadian income taxes related to our operations is included in the accompanying consolidated financial statements, because asstatements. As a partnership we are not subject to federal state or provincialstate income tax and the tax effect of our activities accrues to the unitholders. Net earningsExcept for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. Individual unitholders will have different investment bases depending upon the timing and price of acquisition of partnership units. Further, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, may differ from the accounting followedCanadian operations acquired in the consolidated financial statements. Accordingly, there could be significant differences between each individual unitholder's tax bases andPacific acquisition, the unitholder's share of the net assets reported in the consolidated financial statements. We do not have access to information about each individual unitholder's tax attributes, and the aggregate tax basis cannot be readily determined. Accordingly, we do not believe that in our circumstances, the aggregate difference would be meaningful information.

                    The Partnership'sPartnership’s Canadian operations are conducted through an operating limited partnership, of which our wholly owned subsidiary PMC (Nova Scotia) Company is the general partner. For Canadian



            tax purposes, the general partner is taxed as a corporation, subject to income taxes and a capital-based tax at federal and provincial levels. For 2003 and 2002,the years presented, these amounts were immaterial. The Canadian entities acquired in the Pacific acquisition are corporations for Canadian tax purposes, thus their operations are subject to income taxes in Canada. For 2006, the income tax provision associated with these operations was not material and the capital-based tax was approximately $0.4 million (U.S.) and $0.5 million (U.S), respectively. In addition, interest payments made by Plains Marketing Canada, L.P. on its intercompany loan from Plains Marketing, L.P. are subject to a 10% Canadian withholding tax, which for 2003 and 2002 totaled $0.4 million and $0.5 million, respectively, and is recorded in other expense.

                    In addition to federalmaterial.

            We estimate (a) income taxes owners of our common units 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 byin the various jurisdictions in which we operate, (b) net deferred tax assets and liabilities based on expected future taxes in the jurisdictions in which we operate, (c) valuation allowances for deferred tax assets and (d) contingent tax liabilities for estimated exposures related to our current tax positions. These estimates are considered a critical accounting estimate because they require projecting future operating results (which is inherently imprecise). Also, these estimates depend on assumptions regarding our ability to generate future taxable income during the periods in which temporary differences are deductible. See Note 7.
            As of December 31, 2006, we have not recorded a valuation allowance against our deferred tax assets for federal net operating loss carryforwards. Management believes that it is more likely than not that we will realize the deferred tax assets associated with the federal net operating loss. Key factors in this assessment include an evaluation of our recent history of taxable earnings and losses (as adjusted), future reversals of temporary differences and identification of other sources of future taxable income, including the identification of tax planning strategies.
            Recent Accounting Pronouncements
            In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115” (“SFAS 159”). SFAS 159 allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value in situations in which they are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. The provisions of SFAS 159 will be effective for fiscal years beginning after November 15, 2007. We are evaluating the impact of adoption of SFAS 159 but do businessnot currently expect the adoption to have a material impact on our financial position, results of operations or own property. A unitholdercash flows.
            In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) Topic 1N, Financial Statements — Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). SAB 108 addresses how the effects of prior-year uncorrected misstatements should be considered when quantifying misstatements in current-year financial statements. SAB 108 requires registrants to quantify misstatements using both the balance sheet and income statement approaches and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. The provisions of SAB 108 are effective for the fiscal years ending after November 15, 2006. The adoption of SAB 108 did not have a material impact on our consolidated financial position, results of operations or cash flows.
            In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures regarding fair value measurements. SFAS 157 does not add any new fair value measurements, but it does change current practice and is intended to increase consistency and comparability in such measurement. The provisions of SFAS 157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The impact, if any, to the company from the adoption of FAS 157 in 2008 will depend on the company’s assets and liabilities that are required to be measured at fair value at that time.


            F-20

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In addition, FIN 48 provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be requiredrecognized or continue to file Canadian federal income tax returns, pay Canadian federal and provincial income taxes, file state income tax returns and pay taxes in various states.

            be recognized as an adjustment to the opening balance of retained earnings (or other appropriate components of equity) for that fiscal year. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are evaluating the impact of the adoption of FIN 48 but do not currently expect the adoption of this new standard to have a material impact on our financial position, results of operations or cash flows.

            Derivative Instruments and Hedging Activities

            We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled commodity trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Beginning January 1, 2001, weWe record all derivative instruments on the balance sheet as either assets or liabilities measured at their fair value under the provisions of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138 (collectively "SFAS 133"). At adoption, and in accordance with the transition provisions of SFAS 133, we recorded a loss of $8.3 million in Other Comprehensive Income ("OCI"), representing the cumulative effect of an accounting change to recognize, at fair value, all cash flow derivatives. We also recorded a noncash gain of $0.5 million in earnings as a cumulative effect adjustment.133. SFAS 133 requires that changes in derivative instruments fair value be recognized currently in earnings unless specific hedge accounting criteria are met, in which case, changes in fair value are deferred to OCIAccumulated Other Comprehensive Income (“AOCI”) and reclassified into earnings when the underlying transaction affects earnings. Accordingly, changes in fair value are included in the current period for (i) derivatives characterized as fair value hedges, (ii) derivatives that do not qualify for hedge accounting and (iii) the portion of cash flow hedges that isare not highly effective in offsetting changes in cash flows of hedged items.

            See Note 6 for further discussion.

            Net Income Per Unit

                    Basic

            Except as discussed in the following paragraph, basic and diluted net income per limited partner unit is determined by dividing net income after deducting the amount allocated to the general partner interest (including its incentive distribution in excess of its 2% interest), by the weighted average number of outstanding limited partner units including common unitsduring the period. Subject to applicability of Emerging Issues Task Force IssueNo. 03-06(“EITF 03-06”), “Participating Securities and subordinated units.the Two-Class Method under FASB Statement No. 128,” as discussed below, Partnership income is first allocated to the general partner based on the amount of incentive distributions. The remainder is then allocated between the limited partners and general partner based on percentage ownership in the Partnership. Other comprehensive
            EITF03-06 addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. Essentially, EITF03-06 provides that in any accounting period where our aggregate net income exceeds our aggregate distribution for such period, we are required to present earnings per unit as if all of the earnings for the periods were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. EITF03-06 does not impact our overall net income or other financial results; however, for periods in which aggregate net income exceeds our aggregate distributions for such period, it will have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of our aggregate earnings is allocated based(as if distributed) to our general partner, even though we make cash distributions on the same effective percentages. basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where aggregate net income does not exceed our aggregate distributions for such period, EITF03-06 does not have any impact on our earnings per unit calculation.


            F-21

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            The following table sets forth the computation of basic and diluted net incomeearnings per limited partner unit for 2003, 2002 and 2001 (in millions, except per unit amounts).unit. The net income available to limited partners and the weighted average limited partner



            units outstanding have been adjusted for the impact of the contingent equity issuance related to the CANPET acquisition for the calculation of diluted net income per limited partnerinstruments considered common unit (See Note 3).

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

            		 
            Net income $59.4 $65.3 $44.2 
            Less:          
             General partner incentive distributions  (4.9) (3.1) (1.1)
             General partner 2% ownership  (1.1) (1.3) (0.9)
              
            		 
            		 
            		 

            Numerator for basic earnings per limited partner unit:
             
             
             
             
             
             
             
             
             
             
             Net income available for common unitholders  53.4  60.9  42.2 
             Effect of dilutive securities:          
              Increase in general partner's incentive distribution—Contingent equity issuance  (0.1) —  — 
              
            		 
            		 
            		 

            Numerator for diluted earnings per limited partner unit
             
            $
            53.3
             
            $
            60.9
             
            $
            42.2
             
              
            		 
            		 
            		 

            Denominator:
             
             
             
             
             
             
             
             
             
             
             Denominator for basic earnings per limited partner unit—weighted average number of limited partner units  52.7  45.5  37.5 
             Effect of dilutive securities:          
              Contingent equity issuance  0.7  —  — 
              
            		 
            		 
            		 

            Denominator for diluted earnings per limited partner unit —weighted average number of limited partner units
             
             
            53.4
             
             
            45.5
             
             
            37.5
             
              
            		 
            		 
            		 

            Basic net income per limited partner unit
             
            $
            1.01
             
            $
            1.34
             
            $
            1.13
             
              
            		 
            		 
            		 

            Diluted net income per limited partner unit
             
            $
            1.00
             
            $
            1.34
             
            $
            1.13
             
              
            		 
            		 
            		 
            equivalents at 2006, 2005 and 2004.

            Note 3—Acquisitions

                         
              Year Ended December 31, 
              2006  2005  2004 
              (In millions, except per unit data) 
            Numerator:            
            Net income $285.1  $217.8  $130.0 
            Less: General partner’s incentive distribution paid  (33.1)  (14.9)  (8.3)
                         
            Subtotal  252.0   202.9   121.7 
            Less: General partner 2% ownership  (5.1)  (4.1)  (2.4)
                         
            Net income available to limited partners  246.9   198.8   119.3 
            Less: EITF03-06 additional general partner’s distribution
            		  (10.8)  (7.2)  — 
                         
            Net income available to limited partners under EITF03-06
            		  236.1   191.6   119.3 
            Less: Limited partner 98% portion of cumulative effect of change in accounting principle  (6.2)  —   3.0 
                         
            Limited partner net income before cumulative effect of change in accounting principle $229.9  $191.6  $122.3 
                         
            Denominator:            
            Basic earnings per limited partner unit (weighed average number of limited partner units outstanding)  81.1   69.3   63.3 
            Effect of dilutive securities:            
            Weighted average LTIP units outstanding(1)  0.8   1.2   — 
                         
            Diluted earnings per limited partner unit (weighed average number of limited partner units outstanding)  81.9   70.5   63.3 
                         
            Basic net income per limited partner unit before cumulative effect of change in accounting principle $2.84  $2.77  $1.94 
            Cumulative effect of change in accounting principle per limited partner unit  0.07   —   (0.05)
                         
            Basic net income per limited partner unit $2.91  $2.77  $1.89 
                         
            Diluted net income per limited partner unit before cumulative effect of change in accounting principle $2.81  $2.72  $1.94 
            Cumulative effect of change in accounting principle per limited partner unit  0.07   —   (0.05)
                         
            Diluted net income per limited partner unit $2.88  $2.72  $1.89 
                         

            (1)Our LTIP awards described in Note 10 that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. The dilutive securities are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in SFAS 128, “Earnings per Share.”
            Note 3 —Acquisitions and Dispositions
            The following acquisitions were accounted for using the purchase method of accounting and the purchase price was allocated in accordance with such method. In addition, 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.


            F-22

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            Significant Acquisitions

            Shell West Texas AssetsPacific Energy Partners, L.P.

            On August 1, 2002,November 15, 2006 we acquiredcompleted our acquisition of Pacific Energy Partners, L.P. (“Pacific”) pursuant to an Agreement and Plan of Merger dated June 11, 2006. The merger-related transactions included: (i) the acquisition from Shell Pipeline CompanyLB Pacific, LP and Equilon Enterprises LLCits affiliates (“LB Pacific”) of the general partner interest and incentive distribution rights of Pacific as well as approximately 5.2 million Pacific common units and approximately 5.2 million Pacific subordinated units for a total of $700 million and (ii) the acquisition of the balance of Pacific’s equity through aunit-for-unit exchange in which each Pacific unitholder (other than LB Pacific) received 0.77 newly issued common units of the Partnership for each Pacific common unit. The total value of the transaction was approximately $2.5 billion, including the assumption of debt and estimated transaction costs. Upon completion of the merger-related transactions, the general partner and limited partner ownership interests in Pacific were extinguished and Pacific was merged with and into the Partnership. The assets acquired in the Pacific acquisition included approximately 2,0004,500 miles of gathering and mainlineactive crude oil pipeline and gathering systems and 550 miles of refined products pipelines, over 13 million barrels of active crude oil and 9 million barrels of refined products storage capacity, a fleet of approximately 75 owned or leased trucks and approximately 8.91.9 million barrels (net to our interest) of above-ground crude oil terminalling and storagerefined products linefill and working inventory. The Pacific assets complement our existing asset base in West Texas (the "Shell acquisition").California, the Rocky Mountains and Canada, with minimal asset overlap but attractive potential vertical integration opportunities. The results of operations and assets and liabilities from this acquisition (the “Pacific acquisition”) have been included in our consolidated financial statements and all three of our segments since November 15, 2006. The purchase price allocation related to the Pacific acquisition is preliminary and subject to change, pending finalization of the valuation of the assets and liabilities acquired.
            The purchase price was calculated as follows (in millions):
                 
            Cash payment to LB Pacific $700.0 
            Value of Plains common units issued in exchange for Pacific common units(1)  1,001.6 
            Assumption of Pacific debt (at fair value)  723.8 
            Estimated transaction costs(2)  30.3 
                 
            Total purchase price $2,455.7 
                 
            (1)Valued at $45.02, which represents the average closing price of Plains common units two days immediately prior and two days immediately after the merger was announced on June 12, 2006.
            (2)Includes investment banking fees, costs associated with a severance plan in conjunction with the acquisition and various other direct acquisition costs.
                 
            Purchase Price Allocation
            		    
            Property, plant and equipment, net $1,411.7 
            Investment in Frontier  8.7 
            Inventory  32.6 
            Pipeline linefill and inventory in third party assets  63.6 
            Intangible assets(1)  72.3 
            Goodwill(2)  843.2 
            Assumption of working capital and other long-term assets and liabilities, including $20.0 of cash  23.6 
                 
            Total purchase price $2,455.7 
                 


            F-23

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            (1)Consists of customer relationships, emissions credits and environmental permits.
            (2)Represents the preliminary amount in excess of the fair value of the net assets acquired and is associated with our view of the future results of operations of the businesses acquired based on the strategic location of the assets and the growth opportunities that we expect to realize as we integrate these assets into our existing business strategy. See Note 2.
            The majority of the acquisition costs associated with the Pacific acquisition was incurred as of December 31, 2006, resulting in total cash paid during 2006 of approximately $723 million.
            The following table shows our calculation of the sources of funding for the acquisition (in millions):
                 
            Fair value of Plains common units issued in exchange for Pacific common units $1,001.6 
            Plains general partner capital contribution  21.6 
            Assumption of Pacific debt (at estimated fair value), net of repayment of Pacific credit facility(1)  433.1 
            Plains new debt incurred  999.4 
                 
            Total sources of funding $2,455.7 
                 
            (1)The assumption of Pacific’s debt and credit facility at fair value was $433.1 million and $290.7 million, respectively. We paid off the credit facility in connection with closing of the transaction.
            Link Energy LLC
            On April 1, 2004, we completed the acquisition of all of the North American crude oil and pipeline operations of Link Energy LLC (“Link”) for approximately $332.3 million, including $268 million of cash (net of approximately $5.5 million subsequently returned to us from an indemnity escrow account) and approximately $64 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 active 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 and liabilities from this acquisition have been included in our consolidated financial statements and in all three of our segments since April 1, 2004.
            The purchase price was allocated as follows and includes goodwill primarily attributed to Link’s gathering and marketing operations (in millions):
                 
            Cash paid for acquisition(1)
            		 $268.0 
            Fair value of net liabilities assumed:
            		    
            Accounts receivable(2)  409.4 
            Other current assets  1.8 
            Accounts payable and accrued liabilities(2)  (459.6)
            Other current liabilities  (8.5)
            Other long-term liabilities  (7.4)
                 
            Total net liabilities assumed  (64.3)
                 
            Total purchase price
            		 $332.3 
                 


            F-24

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

                 
            Purchase price allocation
            		    
            Property and equipment $260.2 
            Inventory  3.4 
            Linefill  55.4 
            Inventory in third party assets  8.1 
            Goodwill  5.0 
            Other long-term assets  0.2 
                 
            Total $332.3 
                 

            (1)Cash paid does not include the subsequent payment of various transaction and other acquisition related costs.
            (2)Accounts receivable and accounts payable are gross and do not reflect the adjustment of approximately $250 million to net settle, based on contractual agreements with our counterparties.
            The total purchase price included (i) approximately $9.4 million in transaction costs, (ii) approximately $7.4 million related to a plan to terminate and relocate employees in conjunction with the acquisition, and (iii) approximately $11.0 million related to costs to terminate a contract assumed in the acquisition. These activities were substantially complete and the majority of the related costs were incurred as of December 31, 2004, resulting in total cash paid during 2004 of approximately $294 million.
            The acquisition was initially funded with cash on hand, borrowings under our then existing revolving credit facilities and under a new $200 million,364-day credit facility. In connection with the acquisition, on April 15, 2004, we completed the private placement of 3,245,700 Class C common units to a group of institutional investors. During the third quarter of 2004, we completed a public offering of common units and the sale of an aggregate of $350 million of senior notes. A portion of the proceeds from these transactions was used to retire the $200 million,364-day credit facility.
            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 $158.5 million in cash (including a deposit of approximately $16 million paid in December 2003) and approximately $0.5 million of transaction and other costs. In December 2003, subsequent to the announcement of the acquisition and in anticipation of closing, we issued approximately 2.8 million common units for net proceeds of approximately $88.4 million, after paying approximately $4.1 million of transaction costs. The proceeds from this issuance were used to pay down our revolving credit facility. At closing, the cash portion of this acquisition was funded from cash on hand and borrowings under our revolving credit facility.
            The principal assets of these entities are:  (i) an approximate 22% undivided joint interest in the Capline Pipeline System, and (ii) an approximate 76% undivided joint interest in the Capwood Pipeline System. The Capline Pipeline System is a633-mile,40-inch mainline crude oil pipeline originating in St. James, Louisiana, and terminating in Patoka, Illinois. The Capwood Pipeline System is a58-mile,20-inch mainline crude oil pipeline originating in Patoka, Illinois, and terminating in Wood River, Illinois. The results of operations and assets and liabilities from this acquisition have been included in our consolidated financial statements and in our pipeline operationstransportation segment since that date. The primary assets included in the transaction were interests in the Basin Pipeline System, the Permian Basin Gathering System and the Rancho Pipeline System.March 1, 2004. These assets complement our existing asset infrastructure in West Texas and represent a transportation link to Cushing, Oklahoma, where we are a provider of storage and terminalling services. 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 entire purchase price was allocated to property and equipment.

            CANPET Energy Group Inc.

                    In July 2001, we acquired the assets of CANPET Energy Group Inc. ("CANPET"), a Calgary-based Canadian crude oil and LPG marketing company, for approximately $24.6 million plus excess inventory at the closing date of approximately $25.0 million. A portionpipelines provide one of the purchase price, payable in common units or cash at our option, was deferred subject to various performance standards being met. In addition, an amount will be paid equivalent to the distributions that would have been paid on the common units assuming (i) the deferred portion of the purchase price was paid in common units and (ii) they had been outstanding since the acquisition date. As of December 31, 2003, we determined that it was beyond a reasonable doubt that the performance standards were met and we recorded additional consideration of $24.3 million (see Note 7) resulting in aggregate consideration of $73.9 million. The deferred consideration was recorded as additional goodwill.

                    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 LPG's. 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. Initial financing for the acquisition was provided through borrowings under our credit facility.



                    The purchase price, as adjusted post-closing, 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 closed 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 (the "Murphy acquisition"), including financing and transaction costs. Initial financing for the acquisition was provided through borrowings under our credit facilities. The purchase included $6.5 million for excess inventory in the pipeline systems. The principal assets acquired include approximately 560 miles of crude oil and condensate transmission 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 primarilyprimary transportation routes for crude oil transportation. The acquired assets are part of our strategyshipped into the Midwestern U.S., and delivered to establish a Canadian operation that complements our operations in the United States.several refineries and other pipelines.

                    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 the acquisition, the volume under the contract was 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.F-25

                    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
            Net working capital items  2.0
            Other property and equipment  0.5
            Other assets, including debt issue costs  0.3
              
            Total $158.4
              
            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            Other Acquisitions

            2003 Acquisitions

                    During 2003, we completed ten acquisitions for aggregate consideration totaling approximately $159.5 million.

            The aggregate consideration includes cash paid, estimated transaction costs, assumed liabilities and estimated near-term capital costs. These acquisitions included mainline crude oil



            pipelines, crude oil gathering lines, terminal and storage facilities, and an underground LPG storage facility. The aggregate purchase price was allocated as follows (in million)millions):

            Crude oil pipelines and facilities $138.0
            Crude oil and LPG storage facilities  7.3
            Trucking equipment and other  7.8
            Office property and equipment  1.2
            Pipeline Linefill  4.7
            Goodwill  0.5
              
              $159.5
              

                 
            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 
                 

            Other Acquisitions
            20022006 Acquisitions

            During 2002,2006, in addition to the ShellPacific acquisition, we completed twosix additional acquisitions for aggregate consideration of approximately $565 million. These acquisitions included (i) 100% of the equity interests of Andrews Petroleum and Lone Star Trucking, which provide isomerization, fractionation, marketing and transportation services to producers and customers of natural gas liquids (collectively, the “Andrews acquisition”), (ii) crude oil gathering and transportation assets and related contracts in South Louisiana (“SemCrude”), (iii) interests in various crude oil pipeline systems in Canada and the U.S. including a 100% interest in the BayMarchand-to-Ostrica-to-Alliance (“BOA”) Pipeline, 64.35% interest in theClovelly-to-Meraux (“CAM”) Pipeline system and various interests in the High Island Pipeline System (“HIPS”), and (iv) three refined products pipeline systems from Chevron Pipe Line Company.
            The purchase prices of these acquisitions, in aggregate were allocated as follows (in millions):
                 
            Inventory $35.1 
            Linefill  19.1 
            Inventory in third party assets  2.3 
            Property and equipment  327.4 
            Goodwill(1)  133.1 
            Intangibles(2)  48.7 
            Net other assets and liabilities  (0.3)
                 
            Total Purchase Price $565.4 
                 
            (1)Represents the preliminary amount in excess of the fair value of the net assets acquired and is associated with our view of the future results of operations of the businesses acquired based on the strategic location of the assets and the growth opportunities that we expect to realize as we integrate these assets into our existing business strategy. See Note 2.
            (2)Consists of customer relationships.
            In addition, in November 2006, we acquired a 50% interest in Settoon Towing for approximately $33 million.
            Pro Forma Data
            The following table presents selected unaudited pro forma financial information incorporating the historical (pre-merger) results of Pacific and our other 2006 business combination transactions. The following pro forma information has been prepared as if the Pacific Merger and our other business combination transactions in 2006 had been completed on January 1, 2005 as opposed to the actual dates that these acquisitions occurred. The pro forma information is based upon available data and includes certain estimates and assumptions made by management. As a result, this pro forma information is not necessarily indicative of our financial results had the transactions actually


            F-26

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            occurred on this date. Likewise, the following unaudited pro forma financial information is not necessarily indicative of our future financial results.
                     
              Year Ended December 31, 
              2006  2005 
              (Unaudited) 
              (In millions, except
            		 
              per unit amounts) 
             
            Revenues $22,996.4  $32,354.9 
            Income before cumulative effect of change in accounting principle $309.2  $225.8 
            Net income $315.5  $225.8 
            Basic income before cumulative effect of        
            change in accounting principle per limited partner unit $2.68  $2.37 
            Basic net income per limited partner unit $2.74  $2.37 
            Diluted income before cumulative effect of change in accounting principle per limited partner unit $2.66  $2.34 
            Diluted net income per limited partner unit $2.72  $2.34 
            2005 Acquisitions
            During 2005, we completed six small transactions for aggregate consideration of approximately $40.3 million. The transactions included crude oil trucking operations and several crude oil pipeline systems along the Gulf Coast as well as in Canada. We also acquired an LPG pipeline and terminal in Oklahoma. In addition, in September 2005, PAA/Vulcan acquired Energy Center Investments LLC (“ECI”), an indirect subsidiary of Sempra Energy, for approximately $250 million. We own 50% of PAA/Vulcan and a subsidiary of Vulcan Capital owns the other 50%. See Note 9 “Related Party Transactions.”
            2004 Acquisitions
            During 2004, in addition to the Link and Capline acquisitions, we completed several other acquisitions for aggregate consideration totaling approximately $15.9$73.1 million including transaction costs.costs and approximately $14.4 million of LPG operating inventory acquired. These acquisitions include crude oil pipeline,mainline and gathering pipelines and marketing assets and a 22% equity interest in a pipeline company. With the exception of $1.3 million that was allocated to goodwill, thepropane storage facilities. The aggregate purchase price was allocated to property and equipment.

            2001 AcquisitionDispositions

                    In December 2001, in addition to the CANPET

            During 2006, 2005 and Murphy acquisitions, we acquired 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 includes a crude oil pipeline and approximately 21,500 barrels of crude oil storage capacity located along the system as well as a truck terminal.

            Note 4—Asset Dispositions

            Shutdown of Rancho Pipeline System

                    We acquired 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, we completed transactions whereby we transferred all of our ownership interest in approximately 240 miles of the total 458 miles of the pipeline in exchange for $4.0 million and approximately 500,000 barrels of crude oil tankage in West Texas. The remaining portion will either be sold or salvaged. No gain or loss has been recorded on the shutdown of the Rancho System or these transactions.

            Other Dispositions

                    During 2003 and 2002,2004, we sold various other property and equipment for proceeds totaling approximately $8.5$4.4 million, $9.4 million and $1.4$3.0 million, respectively. A gain of approximately $0.6$2.1 million, was recognized in 2003a loss of $3.2 million, and no gain or loss was recognized in 2002. In December 2001, we sold excess communications equipment and recognized a gain of $1.0 million.



            Note 5—Industry Credit Markets

                    Throughout the latter part$0.6 million were recognized in 2006, 2005, and 2004, respectively. These gains and losses are included as a component of 2001depreciation and all of 2002, there have been significant disruptions and extreme volatilityamortization in the financial markets and credit markets. Becauseconsolidated statements of operations.


            F-27

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            Note 4 — Debt
            Debt consists of the following:
                     
              December 31,
            		  December 31,
            		 
              2006  2005 
              (In millions) 
             
            Short-term debt:
            		        
            Senior secured hedged inventory facility bearing interest at a rate of 5.8% and 4.8% at December 31, 2006 and 2005, respectively $835.3  $219.3 
            Working capital borrowings, bearing interest at a rate of 5.9% and 5.0% at December 31, 2006 and 2005, respectively(1)  158.2   155.4 
            Other  7.7   3.7 
                     
            Total short-term debt  1,001.2   378.4 
            Long-term debt:
            		        
            4.75% senior notes due August 2009, net of unamortized discount of $0.4 million and $0.6 million at December 31, 2006 and 2005, respectively  174.6   174.4 
            7.75% senior notes due October 2012, net of unamortized discount of $0.2 million and $0.2 million at December 31, 2006 and 2005, respectively  199.8   199.8 
            5.63% senior notes due December 2013, net of unamortized discount of $0.5 million and $0.5 million at December 31, 2006 and 2005, respectively  249.5   249.5 
            7.13% senior notes due June 2014, net of unamortized premium of $8.8 million at December 31, 2006  258.8   — 
            5.25% senior notes due June 2015, net of unamortized discount of $0.6 million and $0.7 million at December 31, 2006 and 2005, respectively  149.4   149.3 
            6.25% senior notes due September 2015, net of unamortized discount of $0.8 million at December 31, 2006  174.2   — 
            5.88% senior notes due August 2016, net of unamortized discount of $0.9 million and $1.0 million at December 31, 2006 and 2005, respectively  174.1   174.0 
            6.13% senior notes due January 2017, net of unamortized discount of $1.8 million at December 31, 2006  398.2   — 
            6.70% senior notes due May 2036, net of unamortized discount of $0.4 million at December 31, 2006  249.6   — 
            6.65% senior notes due January 2037, net of unamortized discount of $5.0 million at December 31, 2006  595.0   — 
                     
            Senior notes, net of unamortized discount(2)  2,623.2   947.0 
            Long-term debt under credit facilities and other  3.1   4.7 
                     
            Total long-term debt(1)(2)  2,626.3   951.7 
                     
            Total debt $3,627.5  $1,330.1 
                     
            (1)At December 31, 2006 and 2005, we have classified $158.2 million and $155.4 million, respectively, of borrowings under our senior unsecured revolving credit facility as short-term. These borrowings are designated as working capital borrowings, must be repaid within one year, and are primarily for hedged LPG and crude oil inventory and New York Mercantile Exchange (“NYMEX”) and IntercontinentalExchange (“ICE”) margin deposits.
            (2)At December 31, 2006, the aggregate fair value of our fixed-rate senior notes is estimated to be approximately $2,671.6 million. The carrying values of the variable rate instruments in our credit facilities approximate fair value primarily because interest rates fluctuate with prevailing market rates, and the credit spread on outstanding borrowings reflect market.


            F-28

            PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            Credit Facilities
            In July 2006, we amended our senior unsecured revolving credit intensive nature offacility to increase the energy industry and extreme financial distress at several large, diversified energy companies, the energy industry has been especially impacted by these developments. Accordingly, we are exposedaggregate capacity from $1.0 billion to an increased level of direct and indirect counterparty credit and performance risk.

                    The majority of our credit extensions and therefore our accounts receivable relate to our gathering and marketing activities that can generally be described as high volume and low margin activities. In our credit approval process, we must determine the amount, if any, of the line of credit to be extended to any given customer$1.6 billion and the formsub-facility for Canadian borrowings from $400 million to $600 million. The amended facility can be expanded to $2.0 billion, subject to additional lender commitments, and amounthas a final maturity 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.July 2011. At December 31, 2003, we had received2006, 2005 and 2004, borrowings of approximately $44.0$158.2 million, of advance cash payments$155.4 million and prepayments from third parties to mitigate credit risk.

            Note 6—Debt

                    Short-term debt consists of the following (in millions):

             
            		 December 31,
             
            		 2003
            		 2002
            Senior secured hedged inventory borrowing facility bearing interest at a rate of
            1.9% at December 31, 2003            		 $100.5 $—
            Senior unsecured $425 million domestic revolving credit facility—working capital borrowings, bearing interest at a rate of 4.0% at December 31, 2003(1)  25.3  —
            Senior secured letter of credit and borrowing facility bearing interest at a rate of
            3.4% at December 31, 2002            		  —  97.7
            Other  1.5  1.5
              
            		 
            Total short-term debt and current maturities of long-term debt $127.3 $99.2
              
            		 
            (1)
            At December 31, 2003, we have classified $25.3$231.8 million, of borrowings under our Senior unsecured domestic revolving credit facility as short-term. These borrowings are designated as working capital borrowingsrespectively, were outstanding under this facility and primarily are for hedged LPG inventory and New York Mercantile Exchange ("NYMEX") margin deposits and must be repaid within one year.
            facility.

                    Long-term debt consists of the following (in millions):

             
            		 December 31,
             
            		 2003
            		 2002
            5.63% senior notes due December 2013, net of unamortized discount of $0.7 million $249.3 $—

            7.75% senior notes due October 2012, net of unamortized discount of $0.3 million and $0.4 million at December 31, 2003 and 2002, respectively
             
             
            199.7
             
             
            199.6

            Senior unsecured $170 million Canadian revolving credit facility, bearing interest at a rate of 2.17% at December 31, 2003
             
             
            70.0
             
             
            —

            Senior secured domestic revolving credit facility, bearing interest at a rate of 4.8% at December 31, 2002
             
             
            —
             
             
            10.4

            Senior secured term B loan, bearing interest at a rate of 3.9% at December 31, 2002
             
             
            —
             
             
            198.0

            Senior secured term loan, bearing interest at a rate of 3.9% at December 31, 2002
             
             
            —
             
             
            99.0

            $30 million Canadian senior secured revolving credit facility, bearing interest at a
            rate of 5.0% at December 31, 2002
             
             
            —
             
             
            2.7
              
            		 

            Total long-term debt(1),(2)
             
            $
            519.0
             
            $
            509.7
              
            		 
            (1)
            At December 31, 2002,
            In November 2006, we classified $9 million of term loan payments due in 2003 as long term due toamended our intent and ability to refinance those maturities using the revolving facility.

            (2)
            At December 31, 2003, we have classified $25.3 million of borrowings under our Senior unsecured domestic revolving credit facility as short-term. These borrowings are designated as working capital borrowings under this facility and primarily are for hedged LPG inventory and NYMEX margin deposits and must be repaid within one year.

            Credit Facilities

                    During November 2003, we refinanced our bank credit facilities with new senior unsecured credit facilities totaling $750 million and a $200 million uncommitted facility for the purpose of financing hedged crude oil. The $750 million of new facilities consist of:

              •
              a four-year, $425 million U.S. revolving credit facility;

              •
              a 364-day, $170 million Canadian revolving credit facility with a five-year term-out option;

              •
              a four-year, $30 million Canadian working capital revolving credit facility; and

              •
              a 364-day, $125 million revolving credit facility.

                    All of the facilities with the exception of the $200 millionsecured hedged inventory facility are unsecured. The $200to increase the capacity under the facility from $800 million to $1.0 billion. We also extended the maturity of the senior secured hedged inventory facility to November 2007. This facility is an uncommitted working capital facility, which will beis used to finance the purchase of hedged crude oil inventory for storage when market conditions warrant. Borrowings under the hedged inventory facility will be securedare collateralized by the inventory purchased under the facility and the associated accounts receivable, and will be repaid fromwith the proceeds from the sale of such inventory.

            Senior Notes

            In November 2006, in conjunction with the Pacific merger, we assumed two issues of Senior Notes with an aggregate principal balance of $425 million. The $175 million of 6.25% Senior Notes are due September 15, 2015 and the $250 million of 7.125% Senior Notes are due June 15, 2014. Interest payments on the 6.25% Senior Notes are due on March 15 and September 15 of each year, and interest payments on the 7.125% Senior Notes are due on June 15 and December 15 of each year. These notes were recorded at fair value for an aggregate amount of $433 million.
            In October 2006, we issued $400 million of 6.125% Senior Notes due 2017 and $600 million of 6.65% Senior Notes due 2037. The notes were sold at 99.56% and 99.17% of face value, respectively. Interest payments are due on January 15 and July 15 of each year. We used the proceeds to fund the cash portion of the merger with Pacific including repayment of amounts outstanding under Pacific’s credit facility. Net proceeds in excess of the cash portion of the merger consideration were used to repay amounts outstanding under our credit facilities and for general partnership purposes. In anticipation of the issuance of these notes, we had entered into $200 million notional principal amount of U.S. treasury locks to hedge the treasury rate portion of the interest rate on a portion of the notes. The treasury locks were entered into at an interest rate of 4.97%. See Note 6.
            During December 2003,May 2006, we completed the sale of $250 million aggregate principal amount of 5.625%6.70% Senior Notes due 2036. The notes were sold at 99.82% of face value. Interest payments are due on May 15 and November 15 of each year. We used the proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.
            During May 2005, we completed the issuance of $150 million of 5.25% senior notes due in December 2013.2015. The notes were issued at 99.5% of face value. Interest payments are due on June 15 and December 15 of each year. We used the proceeds to repay amounts outstanding under our credit facilities and for general partnership purposes.
            In each instance, the notes were co-issued by Plains All American Pipeline, L.P. and a 100% owned consolidated 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 two subsidiaries which are minor.with assets regulated by the California Public Utility Commission, and certain other minor subsidiaries. See Note 12.

                    During September 2002, we completed the sale of $200 million of 7.75% senior notes due in October 2012. The notes were issued by Plains All American Pipeline,
            F-29

            PLAINS ALL AMERICAN PIPELINE, L.P. and a 100% owned consolidated finance subsidiary (neither of which have independent assets or operations) at a discount of $0.4 million, resulting in an effective interest rate of 7.78%. Interest payments are due on April 15 and October 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 which are minor.

            AND SUBSIDIARIES
            NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

            Covenants and Compliance

            Our credit facilities, the indenture governing the 5.625% senior notesagreements and the indentureindentures governing the 7.75% senior notes contain cross default provisions. Our credit facilitiesagreements 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:

              •
              incur indebtedness if certain financial ratios are not maintained;

              •
              grant liens;

              •
              engage in transactions with affiliates;

              •
              enter into sale-leaseback transactions;

              •
              sell substantially all of our assets or enter into a merger or consolidation

              • incur indebtedness if certain financial ratios are not maintained;
              • grant liens;
              • engage in transactions with affiliates;
              • enter into sale-leaseback transactions; and
              • sell substantially all of our assets or enter into a merger or consolidation.

              Our credit facilities treatfacility treats a change of control as an event of default and also requirerequires us to maintain:

                •
                maintain a debtdebt-to-EBITDA coverage ratio which will not be greater than: 4.50than 4.75 to 1.0 on all outstanding debt, and 5.25 to 1.0 on all outstanding debt during an acquisition period (generally, the period consisting of three fiscal quarters following an acquisition); and

                •
                an interest coverage ratio that is not lessacquisition greater than 2.75 to 1.0.

              $50 million).

              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 facilitiesfacility 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 our partnership agreement.available cash is not restricted. We are currently in compliance with the covenants contained in our credit facilitiesagreements and indentures.

              Letters of Credit

              As is customary in our industry, and 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. OurThese letters of credit are issued under our credit facility, and 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 periods of up to seventy-day periodsseventy days and are terminated upon completion of each transaction. At December 31, 20032006 and 2002,2005, we had outstanding letters of credit of approximately $57.9$185.8 million and $52.5$55.5 million, respectively. In addition to changes in the level of activity and other factors, the amount of letters of credit outstanding varies based on NYMEX crude oil prices, which were $32.52 per barrel and $29.45 per barrel at December 31, 2003 and 2002, respectively.

              Maturities
              F-30

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              Maturities
              The weighted average life of our long-term debt outstanding at December 31, 2003,2006 was approximately 914.8 years and all balances mature in 2009 or later.

              the aggregate maturities for the next five years are as follows (in millions):

                   
              Calendar
              		   
              Year
              		 Payment 
               
              2007 $— 
              2008  1.0 
              2009  175.3 
              2010  0.9 
              2011  — 
              Thereafter  2,450.9 
                   
              Total(1) $2,628.1 
                   
              (1)Excludes aggregate unamortized discount of $1.8 million on our various senior notes.
              Note 5 —Partners’ Capital and Distributions
              Note 7—Partners' Capital and Distributions

              Units Outstanding

                      Partners'

              Partners’ capital at December 31, 20032006 consists of (1) 50,809,746109,405,178 common units including 1,307,190 Class B common units,outstanding, representing a 85.4%98% effective aggregate ownership interest in the Partnership and its subsidiaries (afterafter giving affecteffect to the general partner interest), (2) 7,522,214 subordinated units representing a 12.6% effective aggregate ownership interest in the Partnership and its subsidiaries (after giving affect to the general partner interest) and (3) a 2% general partner interest.

              Conversion of Class B and Class C Common Units

              In accordance with a common unitholder vote at a special meeting on January 20, 2005, each Class B common unit and Class C common unit became convertible into one common unit upon request of the holder. In February 2005, all of the Class B and Class C common units converted into common units. The Class B common units are initially and Class C common units werepari passu with common units with respect to distributions,quarterly distributions.
              Conversion of Subordinated Units
              Pursuant to the terms of our Partnership Agreement and are convertible intohaving satisfied the financial tests contained therein, in November 2003, 25% of the subordinated units converted to common units upon approval ofon a majorityone-for-one basis. In February 2004, all of the remaining subordinated units converted to common unitholders. The Class B unitholders may request that we call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B common unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured

              one-for-one basis.


              within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, Class B common units have the same voting rights as the common units.

              Subordinated Units and Conversion

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

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

              unitholders.

              General Partner Incentive Distributions

                      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 the general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.450 per unit ("MQD"), 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit (referred to as "incentive distributions"). Cash distributions on our outstanding units and the portion of the distributions representing an excess over the MQD were as follows:

               
              		 Year
               
              		 2003
              		 2002
              		 2001
               
              		 Distribution
              		 Excess
              over MQD
              		 Distribution
              		 Excess
              over MQD
              		 Distribution
              		 Excess
              over MQD
              First Quarter $0.5500 $0.1000 $0.5250 $0.0750 $0.4750 $0.0250
              Second Quarter $0.5500 $0.1000 $0.5375 $0.0875 $0.5000 $0.0500
              Third Quarter $0.5500 $0.1000 $0.5375 $0.0875 $0.5125 $0.0625
              Fourth Quarter $0.5625 $0.1125 $0.5375 $0.0875 $0.5125 $0.0625

              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 of our cash and cash equivalents on hand at the end of each quarter, less reserves established by our general partner for future requirements.

                      During 2003,
              F-31

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              General Partner Incentive Distributions
              Our general partner is entitled to receive incentive distributions if the amount we paid distributionsdistribute with respect to any quarter exceeds levels specified in our partnership agreement. Under the quarterly incentive distribution provisions, generally the general partner is entitled, without duplication, to 15% of approximately $121.8 million ($2.19 on aamounts we distribute in excess of $0.450 per unit, basis)referred to as our minimum quarterly distributions (“MQD”), 25% of the amounts we distribute in excess of $0.495 per unit and 50% of amounts we distribute in excess of $0.675 per unit (referred to as “incentive distributions”).
              Upon closing of the Pacific acquisition, our general partner agreed to reduce the amount of its incentive distributions as follows: (i) $5 million per quarter for the first four quarters, (ii) $3.75 million per quarter for the next eight quarters, (iii) $2.5 million per quarter for the next four quarters, and (iv) $1.25 million per quarter for the final four quarters. Pursuant to this agreement, the first reduction was with respect to the incentive distribution paid to the general partner on February 14, 2007, which was reduced by $5 million. The total reduction in incentive distributions will be $65 million.
              Per unit cash distributions on our outstanding units and the portion of the distributions representing an excess over the MQD were as follows:
                                       
                Year 
                2006  2005  2004 
                   Excess
              		     Excess
              		     Excess
              		 
                Distribution(1)  over MQD  Distribution(1)  over MQD  Distribution(1)  over MQD 
               
              First Quarter $0.6875  $0.2375  $0.6125  $0.1625  $0.5625  $0.1125 
              Second Quarter $0.7075  $0.2575  $0.6375  $0.1875  $0.5625  $0.1125 
              Third Quarter $0.7250  $0.2750  $0.6500  $0.2000  $0.5775  $0.1275 
              Fourth Quarter $0.7500  $0.3000  $0.6750  $0.2250  $0.6000  $0.1500 
              (1)Distributions represent those declared and paid in the applicable period.
              Total cash distributions made were as follows (in millions, except per unit amounts):
                                    
                Distributions Paid 
                Common
              		  Subordinated
              		  GP     
              Year
              		 Units  Units (1)  Incentive  2%   Total 
              2006 $224.9  $—  $33.1  $4.6   $262.6 
              2005 $178.4  $—  $15.0  $3.6   $197.0 
              2004 $142.9  $4.2  $8.3  $3.0   $158.4 
                                    
              (1)The subordinated units converted to common units in 2004.
              On January 16, 2007, we declared a cash distribution of $0.8000 per unit on our outstanding common units. The distribution was paid on February 14, 2007 to unitholders of record on February 2, 2007, for the period October 1, 2006 through December 31, 2006. The total distribution paid was approximately $104.6 million, with approximately $92.7$87.5 million paid to our common unitholders $21.9 million paid to our subordinated unitholders and $2.3$1.8 million and $4.9$15.3 million paid to our general partner for its general partner and incentive distribution interests, respectively.


              F-32

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              Equity Offerings
              During 2002,the three years ended December 31, 2006, we paid distributionscompleted the following equity offerings of approximately $99.8 million ($2.11 on a per unit basis), with approximately $73.6 million paid to our common unitholders, $21.1 million paid to our subordinated

              units.

              unitholders and $2.0 million and $3.1 million paid to our general partner for its general partner and incentive distribution interests, respectively.

                      During 2001, we paid distributions
                                       
                   Gross
              		  Proceeds
              		  GP
              		     Net
              		 
              Period
              		 Units  Unit Price  from Sale  Contribution  Costs  Proceeds 
                (In millions, except per unit amounts) 
               
              December 2006(1)  6,163,960  $48.67  $300.0  $6.1  $(0.5) $305.6 
              July/August 2006(1)  3,720,930  $43.00  $160.0  $3.3  $(0.1) $163.2 
              March/April 2006(1)  3,504,672  $42.80  $150.0  $3.0  $(0.6) $152.4 
              September/October 2005(1)  5,854,000  $42.00  $246.0  $5.0  $(9.1) $241.9 
              February 2005(1)  575,000  $38.13  $21.9  $0.5  $(0.1) $22.3 
              July/August 2004  4,968,000  $33.25  $165.2  $3.4  $(7.7) $160.9 
              April 2004(1)  3,245,700  $30.81  $99.3  $2.0  $(0.1) $101.2 

              (1)These offerings involved related parties. See Note 9 “Related Party Transactions.”
              Payment of approximately $75.9 million ($1.95 on a per unit basis), with approximately $53.8 million paid to our common unitholders, $19.5 million paid to our subordinated unitholders and $1.5 million and $1.1 million paid to our general partner for its general partner and incentive distribution interests, respectively.

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

              Equity OfferingsDeferred Acquisition Price

                      In December 2003, we completed a public offering of 2,840,800 common units for $31.94 per unit. The offering resulted in gross proceeds of approximately $90.7 million from the sale of the units and approximately $1.8 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $4.1 million. Net proceeds of approximately $88.4 million were used to reduce outstanding borrowings under our revolving credit facility.

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

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

                      In August 2002, we completed a public offering of 6,325,000 common units for $23.50 per unit. The offering resulted in cash proceeds of approximately $148.6 million from the sale of the units and approximately $3.0 million from our general partner's proportionate capital contribution. Total costs associated with the offering, including underwriter fees and other expenses, were approximately $6.6 million. Net proceeds of approximately $145.0 million were used to reduce outstanding borrowings under the domestic revolving credit facility.

                      In May 2001, we completed a public offering of 3,966,700 common units. Total net cash proceeds from the offering, including our former general partner's proportionate contribution, were approximately $100.7 million. In addition, in October 2001, we completed a public offering of 4,900,000 common units. Net cash proceeds from the offering, including our general partner's proportionate contribution, were approximately $126.0 million. The net proceeds were used to repay borrowings under our revolving credit facility, a portion of which was used to finance our Canadian acquisitions.



              Contingent Equity Issuance

              In connection with the CANPET acquisition in July 2001, a portion$26.5 million Canadian of the purchase price, payable in common units or cash at our option, was deferred subject to various performance objectives being met. These objectives have beenwere met as of December 31, 2003 and the deferred amount is payablean increase to goodwill for this liability was recorded as of that date. The liability was satisfied on April 30, 2004.2004 with the issuance of approximately 385,000 common units and the payment of $6.5 million in cash. The number of common units issued in satisfaction of the deferred payment will dependwas based upon $34.02 per unit, the average trading price of our common units for a theten-day trading period prior to the payment date, and thea Canadian anddollar to U.S. dollar exchange rate onof 1.35 to 1, the averagenoon-day exchange rate for theten-day trading period prior to the payment date. In addition, an amount will beincremental $3.7 million in cash was paid equivalent tofor the distributions that would have been paid on the common units had they been outstanding since the acquisition was consummated. At our option, the deferred payment may be paid in cash rather than the issuance of units. Assuming the entire obligation is satisfied with common units, based on the foreign exchange rate in effect at December 31, 2003, (1.30 to 1 Canadian dollar to U.S. dollar exchange rate) and an estimated $33.35 per unit price, approximately 613,000 units would be issued and approximately $3.9 million would be paid related to distributions. We currently anticipate that one-thirdeffective date of the contingent purchase price and all of the amount related to past distributions will be paid in cash and the remainder will be settled with approximately 409,000 common units.

              Note 8—Derivatives and Financial Instruments

              acquisition.

              Note 6 —Derivatives and Financial Instruments
              We utilize various derivative instruments to (i) manage our exposure to commodity price risk, (ii) engage in a controlled commodity trading program, (iii) manage our exposure to interest rate risk and (iv) manage our exposure to currency exchange rate risk. Our risk management policies and procedures are designed to monitor interest rates, currency exchange rates, NYMEX, ICE andover-the-counter positions, andas well as physical volumes, grades, locations and delivery schedules to help ensure that our hedging activities address our market risks. WeOur policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. We calculate hedge effectiveness on a quarterly basis. This process includes specific identification of the hedging instrument and the hedged transaction, the nature of the risk being hedged and how the hedging instrument'sinstrument’s effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, we assess whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows or the fair value of hedged items.

              Summary of Financial Impact
              The majority of our derivative activity is related to our commodity price-risk hedging activities. Through these activities, we hedge our exposure to price fluctuations with respect to crude oil, LPG and natural gas as well as with respect to expected purchases, sales and transportation of these commodities. The majority of the instruments that

                      The following
              F-33

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              qualify for hedge accounting are cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedges are deferred to AOCI and recognized in revenues or crude oil and LPG purchases and related costs in the periods during which the underlying physical transactions occur. Derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that is anot highly effective, as defined in SFAS 133, in offsetting changes in cash flows of the hedged items, aremarked-to-market in revenues each period.
              A summary of the financialearnings impact of all derivative activities, including the derivative instrumentschange in fair value of open derivatives and hedgingsettled derivatives taken to earnings during 2006 and 2005, is as follows (in millions, losses designated in brackets):
                                       
                For the Year Ended
              		  For the Year Ended
              		 
                December 31, 2006  December 31, 2005 
                Mark-to-
              		        Mark-to-
              		       
                market, net  Settled  Total  market, net  Settled  Total 
               
              Commodity price-risk hedging $(3.0) $113.3  $110.3  $(21.5) $39.4  $17.9 
              Controlled trading program  —   —   —   —   (0.2)  (0.2)
              Interest rate risk hedging  —   (1.5)  (1.5)  —   (1.6)  (1.6)
              Currency exchange rate risk hedging  (1.4)  0.8   (0.6)  2.6   (0.3)  2.3 
                                       
              Total $(4.4) $112.6  $108.2  $(18.9) $37.3  $18.4 
                                       
              The breakdown of the netmark-to-market impact to earnings between derivatives that do not qualify for hedge accounting and the ineffective portion of cash flow hedges is as follows (in millions, losses designated in brackets):
                       
                For the year ended 
                December 31,
              		  December 31,
              		 
                2006  2005 
               
              Derivatives that do not qualify for hedge accounting $(5.6) $(18.1)
              Ineffective portion of cash flow hedges  1.2   (0.8)
                       
              Total $(4.4) $(18.9)
                       
              The majority of the derivatives that do not qualify for hedge accounting treatment are related to activities discussed below. At December 31, 2003,associated with our storage assets as these contracts will not necessarily result in physical delivery.
              The following table summarizes the net assets and liabilities on our consolidated balance sheet includes assetsthat are related to the fair value of $27.9our open derivative positions (in millions):
                       
                December 31, 
                2006  2005 
               
              Other current assets $55.2  $45.7 
              Other long-term assets  9.0   5.5 
              Other current liabilities  (77.3)  (72.5)
              Other long-term liabilities and deferred credits  (21.4)  (6.5)
                       
              Net asset (liability) $(34.5) $(27.8)
                       


              F-34

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              The net liability related to the fair value of our open derivative positions consists of unrealized gains/losses recognized in earnings and unrealized gains/losses deferred to AOCI as follows, by category (in millions, losses designated in brackets):
                                       
                December 31, 2006  December 31, 2005 
                Net asset
              		        Net asset
              		       
                (liability)  Earnings  AOCI  (liability)  Earnings  AOCI 
               
              Commodity price-risk hedging $(32.5) $(18.9) $(13.6) $(27.2) $(16.0) $(11.2)
              Controlled trading program  —   —   —   —   —   — 
              Interest rate risk hedging  —   —   —   —   —   — 
              Currency exchange rate risk hedging  (2.0)  (2.0)  —   (0.6)  (0.6)  — 
                                       
                $(34.5) $(20.9) $(13.6) $(27.8) $(16.6) $(11.2)
                                       
              In addition to the $13.6 million ($22.0 million current), liabilities of $28.1 million ($17.1 million current) and related unrealized losses deferred to OCI of $1.6 million related toAOCI for open derivative positions. Revenues for the year ended December 31, 2003 includepositions, AOCI also includes a noncash gaindeferred loss of $0.4approximately $6.2 million ($1.4 million noncash gain net of the reversal of the prior period fair value adjustment relatedthat relates to contractsterminated interest rate swaps that settled during the current year). Our hedge-related assets and liabilities are included in other current and non-current assets and liabilities in the consolidated balance sheet. In addition, during the fourth quarter of 2003 we terminated andwere cash settled three interest-rate risk hedging instruments for approximately $6.2 million.in connection with the refinancing of debt agreements over the past four years. The net deferred loss related to these instruments was deferred in OCI and is being amortized intoto interest expense over the original terms of the terminated instruments (approximately fifty percent over three years and the remaining fifty percent over ten years).

                      As of December 31, 2003, theinstruments.

              The total amount of deferred net losses recorded in OCIAOCI are expected to be reclassified to future earnings, contemporaneously with the related physical purchase or delivery of the underlying commodity or payments of interest. DuringOf the periods ended December 31, 2003 and 2002, no amounts were reclassified to earnings from OCI in connection with forecasted transactions that were no longer considered probable of occurring. Based on the aggregate amountstotal net loss deferred in OCIAOCI at December 31, 2003,2006, a net loss of $0.4$14.3 million will be reclassified tointo earnings in the next twelve



              months months; the remaining net loss will be reclassified at various intervals (ending in 2016 for amounts related to our terminated interest rate swaps and the remainder by 2013. Since2009 for amounts related to our commodity price-risk hedging). Because a portion of these amounts areis based on market prices at the current period end, actual amounts to be reclassified will differ and could vary materially as a result of changes in market conditions.

              During the year ended December 31, 2006 and 2005, no amounts were reclassified to earnings from AOCI in connection with forecasted transactions that were no longer considered probable of occurring.

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

              Commodity Price RiskPrice-Risk Hedging

              We hedge our exposure to price fluctuations with respect to crude oil, LPG, refined products, and LPG in storage,natural gas, and expected purchases, sales and transportation of these commodities. The derivative instruments utilizedwe use consist primarily of futures and option contracts traded on the NYMEX, ICE andover-the-counter transactions, including crude oil swap and option contracts entered into with financial institutions and other energy companies (see Note 5 for a discussion of the mitigation of credit risk).companies. In accordance with SFAS 133, these derivative instruments are recorded inrecognized on the balance sheet as assets or liabilities at their fair values.value. The majority of our commodity price risk derivativethe instruments that qualify for hedge accounting asare cash flow hedges. Therefore, the corresponding changes in fair value for the effective portion of the hedgehedges are deferred in OCIinto AOCI and recognized in revenues or crude oil and LPG purchases and related costs in the periods during which the underlying physical transactions occur. At December 31, 2003 there was an unrealized gain of $2.1 million deferred in OCI related to our commodity price risk activities. All of these deferred positions mature by December 2004. An unrealized gain of $1.2 million related to these activities was deferred in OCI at December 31, 2002. For each of the three years ended December 31, 2003, income of $0.5 million, $0.3 million and $0.4 million (excluding the impact of the adoption of SFAS 133), respectively, was included in revenues due to changes in the fair value of derivatives that do not qualify for hedge accounting and the portion of cash flow hedges that are not highly effective. We have determined that substantially all of our physical purchase and sale agreements qualify for the normal purchase and sale exclusion and thus are not subject to SFAS 133. Physical transactions that are derivatives and are ineligible, or become ineligible, for the normal purchase and sale treatment (e.g. due to changes in settlement provisions) are recorded on the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues.
              The majority of the unrealized losses that have been recognized in earnings relate to activities associated with our storage assets. In general, revenue from storing crude oil is reduced in a backwardated market (when oil prices for future deliveries are lower than for current deliveries), as there is less incentive to store crude oil frommonth-to-month. We enter into derivative contracts that will offset the reduction in revenue by generating offsetting gains in a backwardated market structure. These derivatives do not qualify for hedge accounting because the


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              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              contracts will not necessarily result in physical delivery. A portion of the net liability as of December 31, 2006 was caused by a reduction in backwardation (a decrease in the amount that the price of future deliveries are lower than current deliveries) from the time that we entered into the derivative contracts to the end of the year. The net gain or loss related to these instruments will offset storage revenue in the period that the derivative instruments are hedging.
              The unrealized losses deferred in AOCI are related to inventory hedges which are mostly short derivative positions that will result in losses when prices rise. These hedge losses are offset by an increase in the physical inventory value and will be reclassed into earnings from AOCI in the same period that the underlying physical inventory is sold.
              Controlled Trading Program

                      While

              Although 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 and an aggregate of 250,000 barrels of LPG.oil. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. In accordance with SFAS 133, these derivative instruments are recorded in the balance sheet as assets or liabilities at their fair value, with the changes in fair value recorded net in revenues. There were no open positions under this program at December 31, 2003 and 2002. The realized earnings impact related to these activities for the years ended December 31, 2003, 2002 and 2001, was a loss of $0.1 million, income of $0.1 million and a loss of $0.9 million, respectively.

              Interest Rate Risk Hedging

                      We also utilize various products, such as interest rate swaps, collars and treasury locks to hedge interest obligations on specific debt issuances, including anticipated debt issuances. All of these instruments are placed

              In November 2006, in conjunction with large creditworthy financial institutions.

                      At December 31, 2003, there was onethe Pacific merger, we assumed interest rate swap outstandingagreements with an aggregate notional principal amount of $50 million. The$80.0 million to receive interest rate swap is based on LIBOR rates and provides forat a LIBORfixed rate of 4.3% expiring7.125% and to pay interest at an average variable rate of six month LIBOR plus 1.67% (set in March 2004. Interestadvance or in arrears depending on the underlying debt being hedged is based on LIBOR plus a margin.



                      The instruments outstanding at December 31, 2002, consisted of interest rate swaps and a treasury lock with an aggregate notional principal amount of $150 million.swap transaction). The interest rate swaps were based on LIBOR ratesmature June 15, 2014 and provided forare callable at the same dates and terms as the 7.125% senior notes. We designated these swaps as a LIBORhedge against changes in the fair value of the 7.125% Senior Notes resulting from market fluctuations to LIBOR. The changes in fair values of the interest rate swaps are recorded in earnings each period. Similarly, the change in fair value of 5.1% for a $50.0 million notional principal amount expiring October 2006 and a LIBOR rate of 4.3% for a $50.0 million notional principal amount expiring March 2004. Interest on the underlying debt that was hedged was based on LIBOR plus a margin. $80.0 million of senior notes, which are expected to be offsetting to changes in the fair value of the interest swaps, are recorded into earnings each period. For the year ended December 31, 2006 we had an immaterial amount of ineffectiveness relating to these interest rate swaps.

              During 2002,August 2006, we entered into atwo treasury locklocks with large creditworthy financial institutions in anticipation of thea debt issuance in conjunction with our acquisition of our 7.75% senior notes due October 2012 and potential subsequent add-on thereto.Pacific. A treasury lock is a financial derivative instrument that enables thea company to lock in the U.S. Treasury Note rate. The U.S. Treasury Note rate was the benchmark interest rate for our anticipated debt issuance. The two treasury locklocks had a combined notional principal amount of $50.0$200 million and an effective interest rate of 4.60%4.97%. The treasury lock matured in January 2003, was extended to March 2003 with an effective interest rate of 4.68%, was converted to a forward starting swap and was subsequently unwound in conjunction with the issuance of our 5.625% Senior Notes.


                      The instruments outstanding at December 31, 2003 and 2002 qualify for hedge accountinglocks were designated as cash flow hedges in accordance with SFAS 133. The effective portion ofand the changes in fair valuesvalue of these hedges is recorded in OCI until the related hedged item impacts earnings. At December 31, 2003, and 2002, there was a $6.5 million unrealized loss and a $9.6 million unrealized loss, respectively,treasury locks were therefore deferred in OCIAOCI. In October 2006, both treasury locks were terminated prior to maturity in connection with the debt issuance in October 2006 for an aggregate cash payment of $2.4 million.

              AOCI includes a deferred loss of approximately $6.2 million that relates to terminated interest rate swaps that were cash settled in connection with the refinancing of debt agreements over the past four years. The deferred loss related to ourthese instruments is being amortized to interest rate risk activities. As discussed above, approximately $6.1 millionexpense over the original terms of the loss deferred in OCI at December 31, 2003, relates to instruments terminated and cash settled during 2003. During 2003 and 2002, there were no amounts recognized in earnings related to hedge ineffectiveness.

              instruments.

              Currency Exchange Rate Risk Hedging

              Because a significant portion of our Canadian business is conducted in Canadian dollars (CAD),and, at times, a portion of our debt is denominated in Canadian dollars, we use certain financial instruments to minimize the risks of


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              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              unfavorable changes in exchange rates. These instruments include forward exchange contracts forward extra option contracts and cross currency swaps. Additionally, at times, a portion of our debt is denominatedThe open foreign currency derivatives that were assumed in Canadian dollars.the Pacific merger do not qualify for hedge accounting in accordance with SFAS 133. At December 31, 2003 we did not have any Canadian dollar debt and at December 31, 2002, $2.7 million2006, our open foreign exchange derivatives consisted of our long-term debt was denominated inforward exchange contracts that exchange Canadian dollars ($4.3 million CAD based(“Cdn”) and US dollars on a Canadian dollar to U.S. dollar exchange rate of 1.58 to 1). All ofnet basis as follows (in millions):
                           
                Canadian Dollars US Dollars Average Exchange Rate
               
              2007(1) $98.3  $84.1  Cdn $1.17 to US $1.00 
              2008 $3.2  $2.8  Cdn $1.16 to US $1.00 
              (1)Of these amounts, Cdn $108.3 was exchanged for US $93.0 on a net basis on January 2, 2007 at an average exchange rate of Cdn $1.16 to US $1.00.
              These financial instruments are placed with large, creditworthy financial institutions.

                      At December 31, 2003, we had forward exchange contracts that allow us to exchange approximately $2.0 million Canadian for at least $1.5 million U.S. quarterly during 2004 and approximately $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 approximately 1.33 to 1 and 1.34 to 1, respectively). In addition, at December 31, 2003, we also had cross currency swap contracts for an aggregate notional principal amount of $23.0 million, effectively converting this amount of our U.S. dollar denominated debt to $35.6 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1). The notional principal amount reduces by $2.0 million U.S. on May 2004 and May 2005 and has a final maturity in May 2006 ($19.0 million U.S.).

                      At December 31, 2002, we had forward exchange contracts and forward extra option contracts that allow us to exchange $3.0 million Canadian for at least $1.9 million U.S. quarterly during 2003 (based on a Canadian dollar to U.S. dollar exchange rate of 1.54 to 1). At December 31, 2002, we also had cross currency swap contracts for an aggregate notional principal amount of $24.8 million, effectively converting this amount of our U.S. dollar denominated debt to $38.3 million of Canadian dollar debt (based on a Canadian dollar to U.S. dollar exchange rate of 1.55 to 1).

                      The forward exchange contracts and forward extra option contracts qualify for hedge accounting as cash flow hedges and the cross currency swaps qualify for hedge accounting as fair value hedges, both in accordance with SFAS 133. Such derivative activity resulted in an unrealized loss of $0.3 million and an unrealized gain of $0.2 million deferred in OCI related to our currency exchange rate cash flow hedges at December 31, 2003 and 2002, respectively. The earnings impact related to our currency exchange rate fair value hedges was a loss of $0.1 million for the year ended December 31, 2003 and nominal for the year ended December 31, 2002.


              Fair Value of Financial Instruments

                      The carrying amounts and fair values of our financial instruments are as follows (in millions):

               
              		 December 31,
              		 
               
              		 2003
              		 2002
              		 
               
              		 Carrying
              Amount
              		 Fair
              Value
              		 Carrying
              Amount
              		 Fair
              Value
              		 
              NYMEX futures $7.5 $7.5 $0.6 $0.6 
              Options and swaps $(3.3)$(3.3)$(0.6)$(0.6)
              Forward exchange contracts $(0.4)$(0.4)$0.1 $0.1 
              Forward extra option contracts $— $— $0.2 $0.2 
              Cross currency swaps $(4.8)$(4.8)$0.3 $0.3 
              Treasury lock $— $— $(3.3)$(3.3)
              Interest rate swaps $(0.4)$(0.4)$(6.3)$(6.3)
              Short and long-term debt under credit facilities $95.3 $95.3 $409.4 $409.4 
              Senior notes $449.0 $482.9 $199.6 $209.0 

                      As of December 31, 2003 and 2002, the carrying amounts of items comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. The carrying amounts of the variable rate instruments in our credit facilities approximate fair value primarily because the interest rates fluctuate with prevailing market rates, while the interest rate on the 5.625% and the 7.75% senior notes is fixed and the fair value is based on quoted market prices.

              The carrying amount of our derivative financial instruments approximate fair value as these instruments are recorded on the balance sheet at their fair value under SFAS 133. Our derivative financial instruments include cross currency swaps,currently include: (i) forward exchange and extra option contracts interest rate swap collar and treasury lock agreements for which fair values are based on current liquidation values. We also havevalues; (ii) over-the-counter option and swap contracts for which fair values are estimated based on quoted prices from various sources such as independent reporting services, industry publications and brokers.brokers; and (iii) NYMEX futures and options for which the fair values are based on quoted market prices. 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. In addition, we have NYMEX futures
              Note 7 —Income Taxes
              Our U.S. and optionsCanadian subsidiaries are not taxable entities in the U.S. and are not subject to U.S. federal or state income taxes as the tax effect of operations is passed through to our unitholders. However, certain of our Canadian subsidiaries (acquired through the Pacific acquisition in 2006) are taxable entities in Canada and are subject to Canadian federal and provincial income taxes.
              Components of the income tax expense for the year are as follows (in millions):
                   
                
              December 31,
              		 
                2006 
              Canadian federal and provincial income tax:    
              Current $0.4 
              Deferred  (0.1)
                   
              Total $0.3 
                   


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              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows (in millions):
                   
                
              December 31,
              		 
                2006 
              Earnings before income tax $285.4 
              Partnership earnings not subject to tax  (285.2)
                   
                 0.2 
              Federal and provincial income tax rate  32.5%
                   
              Income tax at statutory rate $0.1 
              Increase as a result of other book versus tax differences  0.2 
                   
                   
              Total tax expense $0.3 
                   
              Deferred tax assets and liabilities, which are included within other long-term liabilities and deferred credits in our consolidated balance sheet, result from the fair values are based on quoted market prices.

              Note 9—Major Customers and Concentration of Credit Risk

              following (in millions):

                   
                December 31, 
                2006 
               
              Deferred tax assets:    
              Book accruals in excess of current tax deductions $4.8 
              Net operating losses carried forward (which expire at various times from 2013 to 2015)  2.8 
                   
              Total deferred tax assets $7.6 
                   
              Deferred tax liabilities:    
              Canadian partnership income subject to deferral $(2.5)
              Property, plant and equipment in excess of tax values  (14.5)
                   
              Total deferred tax liabilities  (17.0)
                   
              Net deferred tax liabilities $(9.4)
                   
              Note 8 —Major Customers and Concentration of Credit Risk
              Marathon Ashland Petroleum Company, LLC (“Marathon”) accounted for 12%14%, 10%11% and 11%10% of our revenues for each of the three years in the period ended December 31, 2003.2006. Valero Marketing & Supply Company (“Valero”) accounted for 10% of our revenues for the year ended December 31, 2006. BP Oil Supply accounted for 14% and 10% of our revenues for the years ended December 31, 2005 and 2004, respectively. No other customers accounted for 10% or more of our revenues during any of the three years. The majority of the revenues from Marathon, Ashland PetroleumValero and BP Oil Supply pertain to our gathering, marketing terminalling and storage operations. We believe that the loss of this customerthese 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.

              Financial instruments that potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. We review credit exposure and financial information of our counterparties and generally require letters of credit for receivables from customers that are not considered credit worthy,creditworthy, unless the credit risk can otherwise be reduced (see Note 5).


              reduced.

              Note 10—Related Party Transactions


              F-38

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              Note 9 —Related Party Transactions
              Reimbursement of Expenses of Our General Partner and Itsits Affiliates

              We do not directly employ any persons to manage or operate our business. These functions are provided by employees ofpay our general partner (or, in the case of our Canadian operations, PMC (Nova Scotia) Company). Our general partner does not receive a management fee, or other compensation in connection with its management of us. Webut we do reimburse our general partner for all direct and indirect costs of services provided to us, incurred on our behalf, including the costs of employee, officer and director compensation and benefits allocable to us, andas well as all other expenses necessary or appropriate to the conduct of our business, and allocable to us. We record these costs on the accrual basis in the period in which our general partner incurs them. 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. Historically, an allocation was made for overhead associated with officers and employees who divided time between us and Plains Resources. As a result of the General Partner Transition, all of the employees and officers of the general partner devote 100% of their efforts to our business and there are no allocated expenses. Total costs reimbursed by us to our general partner in for the years ended December 31, 2003, 20022006, 2005 and 20012004 were approximately $88.1$204.6 million, $70.8$165.2 million and $31.3$151.0 million respectively. Total costs reimbursed by usAmounts due to our former general partner and Plains Resources were approximately $31.2 million for the year endedat December 31, 2001.

              2006 and 2005 were $0.8 million and $6.8 million, respectively.

              Vulcan Energy Corporation
              As of December 31, 2006, Vulcan Energy Corporation (“Vulcan Energy”) and its affiliates owned approximately 54% of our general partner interest, as well as approximately 11.3% of our outstanding limited partner units.
              Voting Agreement
              In August 2005, one of the owners of our general partner notified the remaining owners of its intent to sell its 19% interest in the general partner. The remaining owners elected to exercise their right of first refusal, such that the 19% interest was purchased pro rata by all remaining owners. As a result of the transaction, the interest of Vulcan Energy increased from 44% to approximately 54%. At the closing of the transaction, Vulcan Energy entered into a voting agreement that restricts its ability to unilaterally elect or remove our independent directors, and separately, our CEO and COO agreed, subject to certain ongoing conditions, to waive certainchange-of-control payment rights that would otherwise have been triggered by the increase in Vulcan Energy’s ownership interest. These ownership changes to our general partner had no impact on us.
              Administrative Services Agreement
              On October 14, 2005, Plains All American GP LLC (“GP LLC”) and Vulcan Energy entered into an Administrative Services Agreement, effective as of September 1, 2005 (the “Services Agreement”). Pursuant to the Services Agreement, GP LLC provides administrative services to Vulcan Energy for consideration of an annual fee, plus certain expenses. Effective October 1, 2006, the annual fee for providing these services was increased to $1 million. The Services Agreement extends through October 2008, at which time it will automatically renew for successive one-year periods unless either party provides written notice of its intention to terminate the Services Agreement. Pursuant to the agreement, Vulcan Energy has appointed certain employees of GP LLC as officers of Vulcan Energy for administrative efficiency. Under the Services Agreement, Vulcan Energy acknowledges that conflicts may arise between itself and GP LLC. If GP LLC believes that a specific service is in conflict with the best interest of GP LLC or its affiliates then GP LLC is entitled to suspend the provision of that service and such a suspension will not constitute a breach of the Services Agreement.
              Crude Oil Marketing AgreementPurchases from Calumet Florida L.L.C.

                      We are the exclusive marketer/purchaser for all

              Until August 12, 2005, Vulcan Energy owned 100% of Plains Resources' and its subsidiaries' equity crude oil production. The marketing agreement with PlainsCalumet Florida L.L.C. (“Calumet”). Calumet is now owned by Vulcan Resources provides that we will purchase for resale at market pricesFlorida, Inc., the majority of Plains Resources'which is owned by Paul G. Allen. We purchase crude oil productionfrom Calumet and paid approximately $45.1 million, $38.1 million and $28.3 million to Calumet in 2006, 2005 and 2004, respectively.


              F-39

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              Investment in PAA/Vulcan Gas Storage, LLC
              PAA/Vulcan, a limited liability company, was formed in 2005. PAA/Vulcan is owned 50% by us and the other 50% is owned by Vulcan Gas Storage LLC, a subsidiary of Vulcan Capital, which is an affiliate of Vulcan Energy. The Board of Directors of PAA/Vulcan is comprised of an equal number of our representatives and representatives of Vulcan Gas Storage and is responsible for whichproviding strategic direction and policy-making. We are responsible for theday-to-day operations. PAA/Vulcan is not a variable interest entity, and we chargedo not have the ability to control the entity; therefore, we account for the investment under the equity method in accordance with APB 18. This investment is reflected in investments in unconsolidated entities in our consolidated balance sheet.
              In September 2005, PAA/Vulcan acquired ECI, an indirect subsidiary of Sempra Energy, for approximately $250 million. ECI develops and operates underground natural gas storage facilities. We and Vulcan Gas Storage LLC each made an initial cash investment of approximately $112.5 million, and Bluewater Natural Gas Holdings, LLC, a subsidiary of PAA/Vulcan (“Bluewater”) entered into a $90 million credit facility contemporaneously with closing. We currently have no direct or contingent obligations under the Bluewater credit facility.
              PAA/Vulcan is developing a natural gas storage facility through its wholly owned subsidiary, Pine Prairie Energy Center, LLC (“Pine Prairie”). Proper functioning of the Pine Prairie storage caverns will require a minimum operating inventory contained in the caverns at all times (referred to as “base gas”). During the first quarter of 2006, we arranged to provide the base gas for the storage facility to Pine Prairie at a price not to exceed $8.50 per million cubic feet. In conjunction with this arrangement, we executed hedges on the NYMEX for the relevant delivery periods of 2007, 2008 and 2009. We received a fee of $0.20 per barrel. This feeapproximately $1 million for our services to own and manage the hedge positions and to deliver the natural gas.
              We and Vulcan Gas Storage are both required to make capital contributions in equal proportions to fund equity requests associated with certain projects specified in the joint venture agreement. For certain other specified projects, Vulcan Gas Storage has the right, but not the obligation, to participate for up to 50% of such equity requests. In some cases, Vulcan Gas Storage’s obligation is subject to adjustment every three years based on then-existing market conditions.a maximum amount, beyond which Vulcan Gas Storage’s participation is optional. For any other capital expenditures, or capital expenditures with respect to which Vulcan Gas Storage’s participation is optional, if Vulcan Gas Storage elects not to participate, we have the years ended December 31, 2003, 2002right to make additional capital contributions to fund 100% of the project until our interest in PAA/Vulcan equals 70%. Such contributions would increase our interest in PAA/Vulcan and 2001,dilute Vulcan Gas Storage’s interest. Once PAA’s ownership interest is 70% or more, Vulcan Gas Storage would have the right, but not the obligation, to make future capital contributions proportionate to its ownership interest at the time.
              In conjunction with the formation of PAA/Vulcan and the acquisition of ECI, PAA and Paul G. Allen provided performance and financial guarantees to the seller with respect to PAA/Vulcan’s performance under the purchase agreement, as well as in support of continuing guarantees of the seller with respect to ECI’s obligations under certain gas storage and other contracts. PAA and Paul G. Allen would be required to perform under these guarantees only if ECI was unable to perform. In addition, we paid Plains Resources approximately $25.7 million, $247.7 million and $223.2 million, respectively,provided a guarantee under one contract with an indefinite life for which neither Vulcan Capital nor Paul G. Allen provided a guarantee. In exchange for the purchase of crude oil underdisproportionate guarantee, PAA will receive preference distributions totaling $1.0 million over ten years from PAA/Vulcan (distributions that would otherwise have been paid to Vulcan Gas Storage LLC). We believe that the agreement, including the royalty share of production, and recognized margins of approximately $0.2 million, $1.8 million and $1.8 million from the marketing fee for the same periods, respectively. In our opinion, these purchases were made at prevailing market prices. In November 2001, the marketing agreement automatically extended for an additional three-year period. 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. We are in the process of negotiating an amended agreement to reflect the separation. As currently in effect, the marketing agreement will terminate upon a "change in control" of Plains Resources or our general partner. The recently announced buyout of Plains Resources stock would constitute a change of control; however, we received assurances prior to the initial announcement that neither Plains Resources nor the buyout group intend for the agreement to terminate.

                      In December 2002, Plains Resources completed a spin-off of one of its subsidiaries, Plains Exploration and Production Company ("PXP") to its shareholders. PXP is a successor participant to the Plains Resources Marketing agreement. For the year ended December 31, 2003, we paid PXP approximately $277.9 million for the purchase of crude oil under the agreement, including the royalty share of production and recognized margins of approximately $1.7 million from the marketing fee. 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. ("Tosco") 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. We are in the process of negotiating the terms of an amended agreement with PXP.



              Separation Agreement

                      A separation agreement was entered into in connection with the General Partner Transition pursuant to which (i) Plains Resources has indemnified us for (a) claims relating to securities laws or regulations in connection with the upstream or midstream businesses, based on alleged acts or omissions occurring on or prior to June 8, 2001 or (b) claims related to the upstream business, whenever arising, and (ii) we have indemnified Plains Resources for claims related to the midstream business, whenever arising. Plains Resources also has agreed to indemnify and maintain liability insurance for the individuals who were, on or before June 8, 2001, directors or officers of Plains Resources or our former general partner.

              Due to Related Parties

                      The balance of amounts due to related parties at December 31, 2003 and 2002 was $27.0 million and $23.3 million, respectively, and was primarily related to crude oil purchased by us but not yet paid as of December 31 of each year.

              Transaction Grant Agreements

                      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. Under these grants, the common units vested based on attaining a targeted operating surplus for a given year. Approximately 70,000 units vested in 2000, with the remainder in 2001. Thefair value of the units and associated distribution equivalent rightsobligation to stand ready to perform is minimal. In addition, we believe the probability that vestedwe would be required to perform under the Transaction Grant Agreementsguaranty is extremely remote; however, there is no dollar limitation on potential future payments that fall under this obligation.

              PAA/Vulcan will reimburse us for all grantees in 2001 were $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.

              Performance Option Plan

                      In connectionallocated costs of PAA’s non-officer staff associated with the General Partner Transition,management andday-to-day operations of PAA/Vulcan and allout-of-pocket costs. In addition, in 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. Infirst fiscal year 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. 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, and 25% of the options vested, in 2002. The options will vest in their entirety immediately upon a change in controlEBITDA (as defined in the grant agreements).PAA/Vulcan LLC agreement) of PAA/Vulcan exceeds $75.0 million, we will receive a distribution from PAA/Vulcan equal to $6.0 million per year for each year since formation of the joint venture, subject to a maximum of 5 years or $30 million. Thereafter, we will receive annually a distribution equal to the greater of $2 million per year or two percent of the EBITDA of PAA/Vulcan.


              F-40

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              Equity Offerings
              In December 2006, we sold 6,163,960 common units, approximately 10% and 10% of which were sold to investment funds affiliated with Kayne Anderson Capital Advisors, L.P. (“KACALP”) and Encap Investments, L.P., respectively. The originalnet proceeds were used to fund capital expenditures, to reduce indebtedness and for general partnership purposes. KAFU Holdings, L.P., which owns a portion of our general partner and has a representative on our board of directors, is managed by KACALP. Affiliates of Encap own a portion of our general partner and have a representative on our board of directors.
              In July and August 2006, we sold a total of 3,720,930 common units, approximately 18.7% and 12.5% of which were sold to investment funds affiliated with Vulcan Capital and KACALP, respectively. The proceeds from this offering were used to fund acquisition costs, repay indebtedness under our credit facility and for general partnership purposes.
              In March and April 2006, we sold 3,504,672 common units, approximately 20% of which were sold to investment funds affiliated with KACALP. The net proceeds were used to fund a portion of the Andrews acquisition, to reduce indebtedness and for general partnership purposes.
              Concurrently with our public offering of equity in September 2005, we sold 679,000 common units pursuant to our existing shelf registration statement to investment funds affiliated with KACALP in a privately negotiated transaction for a purchase price underof $40.512 per unit (equivalent to the options is $22 per subordinated unit, declining over timepublic offering price less underwriting discounts and commissions).
              On February 25, 2005, we issued 575,000 common units in an amount equala private placement to 80%a subsidiary of each quarterly distribution per unit. As of February 17, 2004, the purchaseVulcan Capital. The sale price was $17.30$38.13 per unit. The terms of future grants may differ from the existing grants. Because the units underlying the plan were contributedunit, which represented a 2.8% discount to the general partner, we will have no obligation to reimburse the general partner for the costclosing price of the units upon exerciseon February 24, 2005. The sale resulted in net proceeds, including the general partner’s proportionate capital contribution ($0.5 million) and net of the options. At December 31, 2003 approximately 371,875 units were outstanding following the exercise of 3,125 options during 2003.

              Stock Option Replacement

                      In connectionexpenses associated with the General Partner Transition, certain memberssale, of approximately $22.3 million.

              In April 2004, we sold 3,245,700 unregistered Class C common units to a group of investors affiliated with KACALP, Vulcan Capital and Tortoise Capital pursuant to Rule 4(2) under the management team that had been employed by Plains Resources were transferred toSecurities Act. Total proceeds from the transaction, after deducting transaction costs and including the general partner. At that time, such individuals held in-the-money but unvested stock options in Plains Resources, whichpartner’s proportionate contribution, were subject to



              forfeiture because of the transfer of employment. Plains Resources, through its affiliates, agreed to substitute a contingent grant of subordinated units (or common units after conversion) with a value equal to the spread on the unvested options, with distribution equivalent rights from the date of grant. The units vest on the same schedule as the stock options would have vested. 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 are provided by Plains Resources, we have no obligation to reimburse the general partner for the cost of such units.

              Benefit Plan

                      A subsidiary of Plains Resources was, until June 8, 2001, our general partner. On that date, such entity transferred the general partner interest to our current general partner, which effective July 1, 2001, maintains a 401(k) defined contribution plan whereby it matches 100% of an employee's contribution (subject to certain limitations in the plan). For the years ended December 31, 2003 and 2002, the defined contribution plan expense was approximately $2.6 million and $2.1 million, respectively. For the period July 1 through December 31, 2001, defined contribution plan expense was approximately $1.1$101 million.

                      Prior to July 1, 2001, Plains Resources maintained a 401(k) defined contribution plan whereby it matched 100% of an employee's contribution (subject to certain limitations in the plan), with matching contributions being made 50% in cash and 50% in common stock of Plains Resources (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). For the period January 1 through June 30, 2001, defined contribution plan expense was $1.0 million.

              Note 11—10 — Long-Term Incentive Plans

              Our general partner has adopted the Plains All American GP LLC 1998 Long-Term Incentive Plan, (the "LTIP")the 2005 Long-Term Incentive Plan and the PPX Successor Long-Term Incentive Plan for employees and directors of our general partner and its affiliates who perform servicesthe Plains All American GP LLC 2006 Long-Term Incentive Tracking Unit Plan for us.non-officer employees. The LTIP consists of two components, a restricted ("phantom") unit plan1998 Plan, 2005 Plan and a unit option plan. The LTIP currently permitsPPX Successor Plan authorize the grant of phantom units and unit options covering an aggregate of 1,425,000 common units. 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 any5.4 million common units fordeliverable upon vesting. Although other types of awards are contemplated under the plans, currently outstanding awards are limited to “phantom” units, which a grant has not yet been made. Our general partner's board of directors also hasmature into 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 ofreceive common units with respect(or cash equivalent) upon vesting. Some awards also include distribution equivalent rights (“DERs”). Subject 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 isapplicable vesting criteria, a "phantom" unit thatDER entitles the grantee to receive, upon the vesting of the phantom unit, a cash payment equal to cash distributions paid on an outstanding common unit (or cash equivalent, depending on the terms of the grant). As of December 31, 2003, aggregate outstanding grants of approximately 1,003,000 have been made to employees, officers and directors of our general partner. As discussed in more detail below, a substantial number of phantom units have recently vested or are expected to vest in the first half of 2004. As of February 17, 2004, giving effect to vested grants, grants of approximately 684,000 unvested phantom units remain outstanding to employees, officers and directors of our general partner. As discussed below, a substantial portion of these phantom units are expected to vest in May 2004. 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. 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. Ourunit.Our general partner will be entitled to reimbursement by us for the costany costs incurred in acquiring common units. In addition, the Partnership may issue up to 975,000 new common units to satisfy deliverysettling obligations under the grants, less any common units issued upon exerciseplans.

              We adopted SFAS 123(R) on January 1, 2006 (see Note 1 for a discussion of unit options underchanges in accounting principles). Under SFAS 123(R) the plan (see below). If we issue new common units upon vestingfair value of the phantom units, the total number of common units outstanding will increase. The Compensation Committee, in its discretion, may grant tandem distribution equivalent rights with respect to phantom units.

                      The phantom units (other than director grants) granted during the subordination period wereawards, which are subject to liability classification, is calculated based on the basic restrictionmarket price of our units at the balance sheet date adjusted for (i) the present value of any distributions that are estimated to occur on the underlying units over the vesting could take placeperiod that will not be received by the award recipients and (ii) an estimated forfeiture rate when appropriate. This fair value is then expensed over the period the awards are earned. For awards with performance conditions, we recognize LTIP expense only after and in proportion to any conversion of subordinated units into common units. Certain grants were subject to additional vesting criteria, primarily related toif the Partnership's performance. In November 2003, 25%achievement of the outstanding subordinated units converted on a one-for-one basis into common units and the remainder of our subordinated units converted into common units in February 2004. As a result, approximately 35,000 phantom units vested in November 2003, approximately 326,000 phantom units vested in February 2004, and we anticipate that approximately 473,000 additional phantom units will vest in May 2004, subject to the satisfaction of service period requirements. Under generally accepted accounting principles, we are required to recognize an expense when itperformance condition is considered probable. When awards with performance conditions that were previously


              F-41

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              considered improbable of occurring become probable thatof occurring, we incur additional LTIP expense necessary to adjust the financial testslife-to-date accrued liability associated with these awards. In addition, we recognize compensation expense for conversion of subordinated units and required distribution levels will be met and thatDER payments in the phantom units will vest. period the payment is earned.
              As of December 31, 2003, we had recorded2006, there were outstanding awards of approximately $28.83.0 million with a weighted average grant-date fair value of approximately $31.94 per unit. Our LTIP awards typically contain performance conditions relative to our annualized distribution level and vest upon the latter of a certain date or upon the attainment of a certain annualized distribution level. Upon our February 2007 annualized distribution of $3.20, approximately 2.2 million of compensation expenseour outstanding awards will have satisfied all performance conditions necessary for vesting and will vest in various increments over the units that vested during 2003next 5 years. Approximately 0.8 million of our outstanding awards have performance conditions requiring the attainment of an annualized distribution of between $3.50 and those that we concluded$4.00 which is not yet considered probable of vesting during 2004. The compensation expense recordedoccurring. However, certain of these awards still outstanding in 2012 will vest regardless of whether or not the performance condition is basedattained. Provided the performance conditions associated with these awards are ultimately attained, these awards will vest in various increments between 2010 and 2012. Approximately 1.6 million of our outstanding awards include DERs. Our DER awards typically contain performance conditions relative to our annualized distribution level and vest upon the actual amounts paid in 2003,earlier of a certain date or fora certain annualized distribution level. The DERs terminate with the unpaid portion, an estimated market price of $33.35 per unit, our share of employment taxes and other related costs.

                      During 2003, we paid cash in lieu of issuing units for approximately 7,500vesting or forfeiture of the phantomunderlying award.

              Our LTIP activity is summarized in the following table (in millions except weighted average grant date fair values):
                                       
                Year Ended December 31, 
                2006  2005  2004 
                   Weighted
              		     Weighted
              		     Weighted
              		 
                   Average
              		     Average
              		     Average
              		 
                   Grant Date
              		     Grant Date
              		     Grant Date
              		 
                Units  Fair Value  Units  Fair Value  Units  Fair Value 
               
              Outstanding at beginning of period  2.2  $34.37   0.1  $23.40   1.0  $17.17 
              Granted(1)  0.9  $26.00   2.2  $34.41   —  $— 
              Vested  —  $—   (0.1) $22.42   (0.9) $16.64 
              Cancelled or forfeited  (0.1) $33.05   —  $—   —  $— 
                                       
              Outstanding at end of period  3.0  $31.94   2.2  $34.37   0.1  $23.40 
                                       
              (1)For 2006, approximately 0.8 million of the awards granted will cash settle upon vesting.
              We recognized expense related to our LTIP of approximately $43 million, $26 million and $8 million during 2006, 2005 and 2004, respectively. As of December 31, 2006, we have an accrued liability of approximately $58 million associated with our LTIP. Cash payments associated with LTIP vestings and DER awards were approximately $2 million and $3 million in 2006, $4 million and $1 million in 2005 and $29 million and $0 in 2004, respectively. Based on our unit price on the applicable vesting date, the total fair value of vested awards was approximately $1.4 million, $4.4 million and $28.3 million during 2006, 2005 and 2004, respectively. No units that vestedwere issued during the year and issued approximately 18,000 common units (after netting for taxes). For those units that vested in February 2004, we paid cash in lieu of issuing units for approximately 104,000 of the phantom units and issued approximately 138,000 new common units (after netting for taxes) in connection with such vesting. We anticipate paying cash for approximately 201,000 of the phantom units expected to vest in May 2004, as well as issuing approximately 181,000 new common units (after netting for taxes) in connection with such vesting.

                      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 will be 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 were each granted 5,000 phantom units. These units vested2006 in connection with the consummationsettlement of vested awards.


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              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              As of December 31, 2006, the General Partner Transition. Additional grants of 5,000 phantom units were made in 2002 to each non-employee directorweighted average remaining contractual life of our general partner. These units vest in 25% incrementsoutstanding awards was approximately three years based on each anniversaryexpected vesting dates. Based on the December 31, 2006 fair value measurement and probability assessment regarding future distributions, we expect to recognize an additional $64 million of June 8, 2001. The first vesting took place on June 8, 2002.

                      Unit Option Plan.    The Unit Option Plan underexpense over the life of our Long-Term Incentive Plan 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 equaloutstanding awards related to the remaining unrecognized fair market value of the unitsvalue. This estimate is based on the datemarket price of grant.

              our limited partner units at December 31, 2006 and actual amounts may differ materially as a result of a change in market price. We estimate that the remaining fair value will be recognized in expense as shown below (in millions):


                   
                LTIP
              		 
                Fair Value
              		 
              Year
              		 Amortization(1) 
               
              2007 $25.3 
              2008  17.7 
              2009  12.1 
              2010  4.9 
              2011  2.0 
              2012  1.8 
                   
              Total $63.8 
                   

              (1)Amounts do not include fair value associated with awards containing performance conditions that are not considered to be probable of occurring at December 31, 2006.
              Note 12—11 — Commitments and Contingencies

              Commitments
              We lease certain real property, equipment and operating facilities under various operating and capital leases. We also incur costs associated with leased land,rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future non-cancellable commitments related to these items at December 31, 2003,2006, are summarized below (in millions):

              2004 $12.7
              2005 $11.2
              2006 $8.8
              2007 $5.3
              2008 $2.8
              Thereafter $0.7

                      Total lease expense incurred
                   
              2007 $37.0 
              2008 $33.9 
              2009 $28.9 
              2010 $22.2 
              2011 $18.6 
              Thereafter $253.7 

              Expenditures related to leases for 2003, 20022006, 2005 and 2001 was $10.52004 were $37.7 million, $8.3$25.7 million and $7.4$20.1 million, respectively. As is common within the industry
              Contingencies
              Pipeline Releases.  In January 2005 and in the ordinary course of business,December 2004, we have also entered into various operational commitments and agreements related to pipeline operations and to marketing, transportation, terminalling and storageexperienced two unrelated releases of crude oil and LPG.

              Litigation

                      Export License Matter.that reached rivers located near the sites where the releases originated. In our gathering and marketing activities, we import and export crude oilearly January 2005, an overflow from and to Canada. Exportsa temporary storage tank located in East Texas resulted in the release of approximately 1,200 barrels of crude oil, a portion of which reached the Sabine River. In late December 2004, one of our pipelines in West Texas experienced a rupture that resulted in the release of approximately 4,500 barrels of crude oil, a portion of which reached a remote location of the Pecos River. In both cases, emergency response personnel under the supervision of a unified command structure consisting of representatives of Plains, the U.S. Environmental Protection Agency (the “EPA”), the Texas Commission on Environmental Quality and the Texas Railroad Commission conductedclean-up


              F-43

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              operations at each site. Approximately 980 and 4,200 barrels were recovered from the two respective sites. The unrecovered oil was removed or otherwise addressed by us in the course of site remediation. Aggregate costs associated with the releases, including estimated remediation costs, are estimated to be approximately $3.0 million to $3.5 million. In cooperation with the appropriate state and federal environmental authorities, we have substantially completed our work with respect to site restoration, subject to some ongoing remediation at the short supply controls of the Export Administration Regulations ("EAR") and must be licensed by the Bureau of Industry and Security (the "BIS") ofPecos River site. EPA has referred these two crude oil releases, as well as several other smaller releases, to the U.S. Department of Commerce.Justice (the “DOJ”) for further investigation in connection with a possible civil penalty enforcement action under the Federal Clean Water Act. We are cooperating in the investigation. Our assessment is that it is probable we will pay penalties related to the two releases. We have determinedaccrued the estimated loss contingency, which is included in the estimated aggregate costs set forth above. It is reasonably possible that wethe loss contingency may have exceededexceed our estimate with respect to penalties assessed by the quantity of crude oil exports authorized by previous licenses. Export of crude oil in excess of the authorized amounts is a violation of the EAR. On October 18, 2002, we submitted to the BIS an initial notification of voluntary disclosure. The BIS subsequently informed us that we could continue to export while previous exports were under review. We applied for and have received a new license allowing for exports of volumes more than adequately reflecting our anticipated needs. On October 2, 2003, we submitted additional information to the BIS. At this time,DOJ; however, we have received no indication whetherfrom EPA or the BIS intends to charge us with a violationDOJ of the EAR or, if so, what penalties wouldmight be assessed.sought. As a result, we cannotare unable to estimate the ultimate impactrange of a reasonably possible loss contingency in excess of our accrual.
              On November 15, 2006, we completed the Pacific acquisition. The following is a summary of the more significant matters that relate to Pacific, its assets or operations.
              The People of the State of California v. Pacific Pipeline System, LLC (“PPS”).  In March 2005, a release of approximately 3,400 barrels of crude oil occurred on Line 63, subsequently acquired by us in the Pacific merger. The release occurred when Line 63 was severed as a result of a landslide caused by heavy rainfall in the Pyramid Lake area of Los Angeles County. As of December 31, 2006, $26 million of remediation costs had been incurred. We estimate additional remediation costs of approximately $1 to $2 million, substantially all of which we expect to incur before June 2007. We anticipate that the majority of costs associated with this release will be covered under a pre-existing PPS pollution liability insurance policy.
              In March 2006, PPS, a subsidiary acquired in the Pacific merger, was served with a four count misdemeanor criminal action in the Los Angeles Superior Court Case No. 6NW01020, which alleges the violation by PPS of two strict liability statutes under the California Fish and Game Code for the unlawful deposit of oil or substances harmful to wildlife into the environment, and violations of two sections of the California Water Code for the willful and intentional discharge of pollution into state waters. The fines that can be assessed against PPS for the violations of the strict liability statutes are based, in large measure, on the volume of unrecovered crude oil that was released into the environment, and, therefore, the maximum state fine that can be assessed is estimated to be approximately $1,100,000, in the aggregate. This amount is subject to a downward adjustment with respect to actual volumes of recovered crude oil, and the State of California has the discretion to further reduce the fine after considering other mitigating factors. Because of the uncertainty associated with these factors, the final amount of the fine that will be assessed for the strict liability offenses cannot be ascertained. We will defend against these charges. In addition to these fines, the State of California has indicated that it may seek to recover approximately $150,000 in natural resource damages against PPS in connection with this matter.

              The mitigating factors may also serve as a basis for a downward adjustment of the natural resource damages amount. We believe that certain of the alleged violations are without merit and intend to defend against them, and that mitigating factors should apply.

              In December 2006 we were informed that the EPA may be intending to refer this matter to the DOJ for the initiation of proceedings to assess civil penalties against PPS. The DOJ has accepted the referral. We understand that the maximum permissible penalty that the EPA could assess under relevant statutes would be approximately $3.7 million. We believe that several mitigating circumstances and factors exist that could substantially reduce the penalty, and intend to pursue discussions with the EPA regarding such mitigating circumstances and factors. Because of the uncertainty associated with these factors, the final amount of the penalty that will be assessed by the EPA cannot be ascertained. Discussions with the DOJ to resolve this matter have commenced.
                      Alfons SperberKosseff v. Plains Resources Inc.Pacific Energy, et al, et. al.case no. BC 3544016. On December 18, 2003,June 15, 2006, a putative class action lawsuit was filed in the Delaware Chancery Court, New CastleSuperior court of California, County entitledof Los Angeles, in which the plaintiff alleged that he was a unitholder of Pacific and he sought to represent a class comprising all of Pacific’s unitholders. The complaint named as defendants Pacific and


              F-44

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESAlfons Sperber v. Plains Resources Inc., et al. This suit,
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              certain of the officers and directors of Pacific’s general partner, and asserted claims of self-dealing and breach of fiduciary duty in connection with the pending merger with us and related transactions. The plaintiff sought injunctive relief against completing the merger or, if the merger was completed, rescission of the merger, other equitable relief, and recovery of the plaintiff’s costs and attorneys’ fees. On September 14, 2006, Pacific and the other defendants entered into a memorandum of settlement with the plaintiff to settle the lawsuit. As part of the settlement, Pacific and the other defendants deny all allegations of wrongdoing and express willingness to settle the lawsuit solely because the settlement would eliminate the burden and expense of further litigation. The settlement is subject to customary conditions, including court approval. As part of the settlement, we (as successor to Pacific) will pay $0.5 million to the plaintiff’s counsel for their fees and expenses, and incur the cost of mailing materials to former Pacific unitholders. If finally approved by the court, the settlement will resolve all claims that were or could have been brought on behalf of a putativethe proposed settlement class of Plains All American Pipeline, L.P. common unit holders, asserts breach of fiduciary dutyin the actions being settled, including all claims relating to the merger, the merger agreement and breach of contract claims againstany disclosure made by Pacific in connection with the Partnership, 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.merger. The complaint seeks to enjoin or rescind a proposed acquisition of allsettlement did not change any of the outstanding stockterms or conditions of Plains Resources Inc.the merger.
              Air Quality Permits.  In connection with the Pacific merger, we acquired Pacific Atlantic Terminals LLC (“PAT”), as well as declaratory relief, an accounting, disgorgementwhich is now one of our subsidiaries. PAT owns crude oil and refined products terminals in northern California. In the impositionprocess of integrating PAT’s assets into our operations, we identified certain aspects of the operations at the terminals that appeared to be out of compliance with specifications under the relevant air quality permit. We conducted a constructive trust,prompt review of the circumstances and an awardself-reported the apparent historical occurrences of damages, fees, expenses and costs, among other things. The Partnership intendsnon-compliance to vigorously defend this lawsuit.

              the Bay Area Air Quality Management District. We are cooperating with the District’s review of these matters.

                      Other Litigation.General.  We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. 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.



              OtherEnvironmental.  We have in the past experienced and in the future likely will experience releases of crude oil into the environment from our pipeline and storage operations. We also may discover environmental impacts from 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. As we expand our pipeline assets through acquisitions, we typically improve on (decrease) the rate of releases from such assets as we implement our standards and procedures, remove selected assets from service and spend capital to upgrade the assets. In the immediate post-acquisition period, however, the inclusion of additional miles of pipe in our operation may result in an increase in the absolute number of releases company-wide compared to prior periods. We experienced such an increase in connection with the Pacific acquisition, which added approximately 5,000 miles of pipeline to our operations, and in connection with the purchase of assets from Link Energy LLC in April 2004, which added approximately 7,000 miles of pipeline to our operations. As a result, we have also received an increased number of requests for information from governmental agencies with respect to such releases of crude oil (such as EPA requests under Clean Water Act Section 308), commensurate with the scale and scope of our pipeline operations. See “— Pipeline Releases” above.
              At December 31, 2006, our reserve for environmental liabilities totaled approximately $39.1 million. At December 31, 2006, we have recorded receivables totaling approximately $11.6 million for amounts which are probable of recovery under insurance and from third parties under indemnification agreements. Although we believe our reserve is adequate, no assurance can be given that any costs incurred in excess of this reserve would not have a material adverse effect on our financial condition, results of operations or cash flows. See Note 13.


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              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              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 overall trend in the environmental insurance industry 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 or incorporate higher retention in our insurance arrangements.
              The occurrence of a significant event not fully insured, indemnified or indemnifiedreserved 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.reasonable, or that we have established adequate reserves to the extent that such risks are not insured.
              Note 12 — Supplemental Condensed Consolidating Financial Information
              In conjunction with the Pacific acquisition, some but not all of our 100% owned subsidiaries have issued full, unconditional, and joint and several guarantees of our Senior Notes. Given that certain, but not all, subsidiaries are guarantors of our Senior Notes, we are required to present the following supplemental condensed consolidating financial information. For purposes of the following footnote, we are referred to as “Parent”, while the “Guarantor Subsidiaries” are PAA Finance Corp.; Plains Marketing, L.P.; Plains Pipeline, L.P.; Plains Marketing GP Inc.; Plains Marketing Canada LLC; Plains Marketing Canada, L.P.; PMC (Nova Scotia) Company; Basin Holdings GP LLC; Basin Pipeline Holdings, L.P.; Rancho Holdings GP LLC; Rancho Pipeline Holdings L.P.; Plains LPG Services GP LLC; Plains LPG Services, L.P.; Lone Star Trucking, LLC; Plains Marketing International GP LLC; Plains Marketing International, L.P; Plains LPG Marketing, L.P.; Rocky Mountain Pipeline System, LLC; Pacific Marketing and Transportation LLC; Pacific Atlantic Terminals LLC; Pacific LA Marine Terminal, LLC; Ranch Pipeline LLC; PEG Canada GP LLC; PEG Canada, L.P.; Pacific Energy Group LLC; Pacific Energy Finance Corporation; Rangeland Pipeline Company; Rangeland Marketing Company; Rangeland Northern Pipeline Company; Rangeland Pipeline Partnership; and Aurora Pipeline Company, Ltd. and “Non-Guarantor Subsidiaries” are Atchafalaya Pipeline, L.L.C.; Andrews Partners, LLC; Pacific Pipeline System, LLC, Pacific Terminals, LLC, Pacific Energy Management LLC and Pacific Energy GP LP.


              F-46

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              The following supplemental condensed consolidating financial information reflects the Parent’s separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Parent’s Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations and the Parent’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent’s investments in its subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting:
              Condensed Consolidating Balance Sheet
                                   
                December 31, 2006 
                Plains
              		  Combined
              		  Combined
              		       
                All
              		  Guarantor
              		  Non-Guarantor
              		       
                American  Subsidiaries  Subsidiaries  Eliminations  Consolidated 
                (In millions) 
               
              ASSETS
              Total current assets $2,573.8  $3,048.7  $97.6  $(2,562.5) $3,157.6 
              Property, plant and equipment, net  —   3,226.9   615.1   —   3,842.0 
              Other Assets
              		                    
              Investment in unconsolidated entities  3,037.7   731.3   —   (3,586.0)  183.0 
              Other assets  23.0   1,197.9   311.4   —   1,532.3 
                                   
              Total assets $5,634.5  $8,204.8  $1,024.1  $(6,148.5) $8,714.9 
                                   
               
              LIABILITIES AND PARTNER’S CAPITAL
              Total current liabilities $34.2  $5,355.9  $14.1  $(2,379.5) $3,024.7 
              Other liabilities
              		                    
              Long-term debt  2,623.2   (273.3)  276.4   —   2,626.3 
              Other long-term liabilities  0.3   84.5   2.3   —   87.1 
                                   
              Total liabilities  2,657.7   5,167.1   292.8   (2,379.5)  5,738.1 
                                   
              Partner’s Capital
              		  2,976.8   3,037.7   731.3   (3,769.0)  2,976.8 
                                   
              Total Liabilities and Partner’s Capital $5,634.5  $8,204.8  $1,024.1  $(6,148.5) $8,714.9 
                                   


              F-47

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              Condensed Consolidating Statement of Operations
                                   
                Year Ended December 31, 2006 
                Plains
              		  Combined
              		  Combined
              		       
                All
              		  Guarantor
              		  Non-Guarantor
              		       
                American  Subsidiaries  Subsidiaries  Eliminations  Consolidated 
                (In millions) 
               
              Net operating revenues $—  $942.4  $16.4  $—  $958.8 
              Field operating costs  —   363.6   6.2   —   369.8 
              General and administrative expenses  —   132.6   1.3   —   133.9 
              Depreciation and amortization  2.4   95.3   2.7   —   100.4 
                                   
              Operating Income  (2.4)  350.9   6.2   —   354.7 
                                   
              Equity earnings in unconsolidated entities  363.1   13.9   —   (369.3)  7.7 
              Interest expense  (77.3)  (8.3)  —   —   (85.6)
              Interest income and other income (expense)  1.7   —   —   —   1.7 
              Income tax expense  —   0.3   —   —   0.3 
                                   
              Income before cumulative effect of change in accounting principle  285.1   356.8   6.2   (369.3)  278.8 
              Cumulative effect of change in accounting principle  —   6.3   —   —   6.3 
                                   
              Net income (loss) $285.1  $363.1  $6.2  $(369.3) $285.1 
                                   


              F-48

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              Condensed Consolidating Statements of Cash Flows
                                   
                Year Ended December 31, 2006 
                Plains
              		  Combined
              		  Combined
              		       
                All
              		  Guarantor
              		  Non-Guarantor
              		       
                American  Subsidiaries  Subsidiaries  Eliminations  Consolidated 
                (In millions) 
               
              CASH FLOWS FROM OPERATING ACTIVITIES
              		                    
              Net income $285.1  $363.1  $6.2  $(369.3) $285.1 
              Adjustments to reconcile to cash flows from operating activities:                    
              Depreciation and amortization  2.4   95.3   2.7   —   100.4 
              Cumulative effect of change in accounting principle  —   (6.3)  —   —   (6.3)
              Inventory valuation adjustment  —   5.9   —   —   5.9 
              SFAS 133mark-to-market adjustment
              		  —   4.4   —   —   4.4 
              Long-Term Incentive Plan charge  —   42.7   —   —   42.7 
              Noncash amortization of terminated interest rate hedging instruments  1.5   —   —   —   1.5 
              Loss on foreign currency revaluation  —   4.1   —   —   4.1 
              Net cash paid for terminated interest rate hedging instruments  (2.4)  —   —   —   (2.4)
              Equity earnings in unconsolidated entities  (363.1)  (13.9)  —   369.3   (7.7)
              Net change in assets and liabilities, net of acquisitions  (491.1)  (158.5)  (7.5)  (45.9)  (703.0)
                                   
              Net cash provided by (used in) operating activities  (567.6)  336.8   1.4   (45.9)  (275.3)
                                   
              CASH FLOWS FROM INVESTING ACTIVITIES
              		                    
              Cash paid in connection with acquisitions, net of $20.0 cash assumed from acquisitions  (703.6)  (560.3)  —   —   (1,263.9)
              Additions to property and equipment  —   (339.4)  (1.6)  —   (341.0)
              Investment in unconsolidated entities  (45.9)  (45.9)  —   45.9   (45.9)
              Cash paid for linefill in assets owned  —   (4.8)  0.2   —   (4.6)
              Proceeds from sales of assets  —   4.4   —   —   4.4 
                                   
              Net cash used in investing activities  (749.5)  (946.0)  (1.4)  45.9   (1,651.0)
                                   
              CASH FLOWS FROM FINANCING ACTIVITIES
              		                    
              Net (repayments) on long-term revolving credit facility  (290.7)  (7.8)  —   —   (298.5)
              Net borrowings on working capital revolving credit facility  —   2.8   —   —   2.8 
              Net borrowings on short-term letter of credit and hedged inventory facility  —   616.0   —   —   616.0 
              Proceeds from the issuance of senior notes  1,242.8   —   —   —   1,242.8 
              Net proceeds from the issuance of common units  642.8   —   —   —   642.8 
              Distributions paid to unitholders and general partner  (262.6)  —   —   —   (262.6)
              Other financing activities  (13.1)  (3.2)  —   —   (16.3)
                                   
              Net cash provided by financing activities  1,319.2   607.8   —   —   1,927.0 
                                   
              Effect of translation adjustment on cash  —   1.0   —   —   1.0 
              Net increase (decrease) in cash and cash equivalents  2.1   (0.4)  —   —   1.7 
              Cash and cash equivalents, beginning of period  0.2   9.4   —   —   9.6 
                                   
              Cash and cash equivalents, end of period $2.3  $9.0  $—  $—  $11.3 
                                   


              F-49

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              At December 31, 2005 and for the years ended December 31, 2005 and December 31, 2004, the Non-Guarantor Subsidiaries were considered minor, as defined byRegulation S-Xrule 3-10(h)(6) and thus, supplemental condensed consolidating financial information is not presented for those periods.
              Note 13 — Environmental Remediation
              We currently own or lease properties where hazardous liquids, including hydrocarbons, are being or have been handled. These properties and the hazardous liquids or associated generated wastes disposed thereon may be subject to CERCLA, RCRA and analogous state and Canadian federal and provincial laws and regulations. Under such laws and regulations, we could be required to remove or remediate 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 operations to prevent future contamination.
              We maintain insurance of various types with 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. Consistent with insurance coverage generally available in the industry, in certain circumstances our insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.
              In addition, we have entered into indemnification agreements with various counterparties in conjunction with several of our acquisitions. 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, minimum thresholds or caps on exposure) and whether to obtain insurance, if available. In some cases, 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 requirements that must be satisfied before indemnification will apply and have term and total dollar limits.
              For instance, in connection with the purchase of assets from Link in 2004, we identified a number of environmental liabilities for which we received a purchase price reduction from Link and recorded a total environmental reserve of $20 million. A substantial portion of these 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 agreed to bear $11 million of the first $20 million of pre-May 1999 environmental issues. We also agreed to bear the first $25,000 per site for new sites which were not identified at the time we entered into the agreement (capped at 100 sites). TNM agreed to pay all costs in excess of $20 million (excluding the deductible for new sites). TNM’s obligations are guaranteed by Shell Oil Products (“SOP”). As of December 31, 2006, we had incurred approximately $7 million of remediation costs associated with these sites; SOP’s share is approximately $1.5 million.
              In connection with the acquisition of certain crude oil transmission and gathering assets from SOP in 2002, SOP 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. SOP made a claim against the policy; however, we do not believe that the claim substantially reduced our coverage under the policy.
              In connection with our 1999 acquisition of Scurlock Permian LLC from MAP, we were indemnified by MAP for any environmental liabilities attributable to Scurlock’s business or properties that occurred prior to the date of the closing of the acquisition. Other than with respect to liabilities associated with two Superfund sites at which it is alleged that Scurlock deposited waste oils, this indemnity has expired or was terminated by agreement.


              F-50

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              As a result of our merger with Pacific, we have assumed liability for a number of ongoing remediation sites, associated with releases from pipeline or storage operations. These sites had been managed by Pacific prior to the merger, and in general there is no insurance or indemnification to cover ongoing costs to address these sites (with the exception of the Pyramid Lake crude oil release). We have evaluated each of the sites requiring remediation, through review of technical and regulatory documents, discussions with Pacific, and our experience at investigating and remediating releases from pipeline and storage operations. We have developed reserve estimates for the Pacific sites based on this evaluation, including determination of current and long-term reserve amounts, which total approximately $21.8 million.
              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 likely will experience releases of crude oil or petroleum products into the environment from our pipeline and storage operations, oroperations. We also may discover environmental impacts from 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.

              Note 13—Environmental Remediation

              As we expand our pipeline assets through acquisitions, we typically improve on (decrease) the rate of releases from such assets as we implement our standards and procedures, remove selected assets from service and spend capital to upgrade the assets. In the immediate post-acquisition period, however, the inclusion of additional miles of pipe in our operation may result in an increase in the absolute number of releases company-wide compared to prior periods. We experienced such an increase in connection with various acquisitions,the Pacific acquisition, which added approximately 5,000 miles of pipeline to our operations, and in connection with the Link acquisition, which added approximately 7,000 miles of pipeline to our operations. As a result, we have also received indemnitiesan increased number of requests for information from governmental agencies with respect to such releases of crude oil (such as EPA requests under CleanWater Act Section 308), commensurate with the sellersscale and scope of our pipeline operations.

              At December 31, 2006, our reserve for environmental exposure, subjectliabilities totaled approximately $39.1 million (approximately $21.8 million of this reserve is related to liabilities assumed as part of the Pacific merger, and $10.4 million is related to liabilities assumed as part of the Link acquisition). Approximately $19.5 million of our prior payment of certain threshold amounts. Basedenvironmental reserve is classified as current (within other current liabilities on our investigationsConsolidated Balance Sheets) and $19.6 million is classified as long-term (within Other long-term liabilities and deferred credits on our Consolidated Balance Sheets). At December 31, 2006, we have recorded receivables totaling approximately $11.6 million for amounts recoverable under insurance and from third parties under indemnification agreements.
              In some cases, the actual cash expenditures may not occur for three to five years. Our estimates used in these reserves are based on all known facts at the time and our assessment of the assets acquiredultimate 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 such acquisitions, we have identified several sites that exceedcosts associated with environmental remediation services and equipment and the threshold limitations under the various indemnities. Although we have not yet determined the total costpossibility of remediation of these sites,existing legal claims giving rise to additional claims. Therefore, although we believe our indemnification arrangements should prevent suchthat the reserve is adequate, no assurances can be made that any costs from havingincurred 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.

                      In connection with our 1999 acquisition of Scurlock Permian LLC from MAP, we were indemnified by MAP for any environmental liabilities attributable to Scurlock's business or properties which occurred prior to the date of the closing of the acquisition. This indemnity applied to claims that exceeded $25,000 individually and $1.0 million in the aggregate. For the indemnity to apply, we were required to assert any claims on or before May 15, 2003. In conjunction with the expiration of this indemnity, we reached agreement with respect to MAP's remaining indemnity obligations. Under the terms of this agreement, MAP will continue to remain obligated for liabilities associated with two Superfund sites at which it is alleged that Scurlock Permian deposited waste oils. In addition, MAP paid us $4.6 million cash as satisfaction of its obligations with respect to other sites. During 2002, we had reassessed previous investigations and completed environmental studies related to environmental conditions associated with our 1999 acquisitions. As a result of that reassessment, we established an additional reserve of $1.2 million.
              F-51

                      As of December 31, 2003, we have approximately $6.6 million reserved associated with our remediation obligations. This amount is approximately equal to the threshold amounts the partnership must incur before the sellers' indemnities take effect. Approximately $1.6 million of our environmental reserve is classified as current and $5.0 million is classified as long-term because in many cases, the actual cash expenditures may not occur for up to ten years or more.

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



              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              Note 14—14 — Quarterly Financial Data (Unaudited):

               
              		 First
              Quarter
              		 Second
              Quarter
              		 Third
              Quarter
              		 Fourth
              Quarter
              		 Total(1)
               
              		 (in thousands, except per unit data)

              2003               
              Revenues $3,281.9 $2,709.2 $3,053.7 $3,545.0 $12,589.8
              Gross margin  46.7  44.0  38.7  41.2  170.6
              Operating income  33.6  31.9  21.0  11.6  98.2
              Net income (loss)  24.4  23.4  11.9  (0.2) 59.4
              Basic net income (loss) per limited partner unit  0.46  0.42  0.20  (0.03) 1.01
              Diluted net income (loss) per limited partner unit  0.46  0.42  0.19  (0.03) 1.00
              Cash distributions per common unit(2) $0.550 $0.550 $0.550 $0.563 $2.21

              2002
               
               
               
               
               
               
               
               
               
               
               
               
               
               
               
              Revenues $1,545.3 $1,985.3 $2,344.1 $2,509.5 $8,384.2
              Gross margin  31.4  34.5  35.3  39.0  140.2
              Operating income  20.8  23.4  23.8  26.7  94.6
              Net income  14.3  17.0  16.3  18.9  65.3
              Basic and diluted net income per limited partner unit  0.31  0.37  0.33  0.35  1.34
              Cash distributions per common unit(2) $0.525 $0.538 $0.538 $0.538 $2.14
              (1)
                                   
                First
              		  Second
              		  Third
              		  Fourth
              		    
                Quarter  Quarter  Quarter  Quarter  Total(1) 
                (In millions, except per unit data) 
               
              2006
              		                    
              Revenues(2) $8,635.1  $4,891.9  $4,525.6  $4,391.8  $22,444.4 
              Gross margin  103.8   124.0   145.8   115.0   488.6 
              Operating income  72.0   96.6   112.8   73.3   354.7 
              Cumulative effect of change in accounting principle  6.3   —   —   —   6.3 
              Net income  63.4   80.3   95.4   46.0   285.1 
              Basic net income per limited partner unit  0.73   0.82   0.90   0.37   2.91 
              Diluted net income per limited partner unit  0.71   0.81   0.89   0.36   2.88 
              Cash distributions per common unit(3) $0.688  $0.708  $0.725  $0.750  $2.87 
              2005
              		                    
              Revenues(2) $6,638.3  $7,160.6  $8,664.2  $8,713.4  $31,176.5 
              Gross margin  69.2   102.1   111.2   95.5   378.0 
              Operating income  47.1   75.9   84.7   67.1   274.8 
              Net income  32.8   62.3   69.0   53.7   217.8 
              Basic net income per limited partner unit  0.43   0.76   0.81   0.65   2.77 
              Diluted net income per limited partner unit  0.43   0.74   0.79   0.64   2.72 
              Cash distributions per common unit(3) $0.613  $0.638  $0.650  $0.675  $2.58 
              (1)The sum of the four quarters does not equal the total year due to rounding.
              (2)Includes buy/sell transactions. See Note 2.
              (3)Represents cash distributions declared and paid in the applicable period.
              Note 15 — Operating Segments
              Prior to the fourth quarter of the four quarters may not equal the total year due2006, we managed our operations through two segments. Due to rounding.

              (2)
              Represents cash distributions declared per common unit for the period indicated. Distributions were paidour growth, especially in the following calendar quarter.

              Note 15—Operating Segments

                      Ourfacilities portion of our business (most notably in conjunction with the Pacific acquisition), we have revised the manner in which we internally evaluate our segment performance and decide how to allocate resources to our segments. As a result, we now manage our operations consist of twothrough three operating segments: (1) Pipeline Operations—engages(i) Transportation, (ii) Facilities, and (iii) Marketing. Prior period disclosures have been revised to reflect our change in interstate and intrastate crude oil pipeline transportation and certain related merchant activities; (2) Gathering, Marketing, Terminalling and Storage Operations—engages in purchases and resales of crude oil and LPG at various points along the distribution chain and the operation of certain terminalling and storage assets. segments.

              We evaluate segment performance based on (i) segment profit and (ii) maintenance capital. We define segment profit as revenues less (i) purchases and related costs, (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 mitigate the actual decline in the value of our principal fixed assets. These maintenance costs are a component of field


              F-52

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              operating costs included in segment profit or in maintenance capital, depending on the nature of the cost. Maintenance capital, which is deducted in determining “available cash,” 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 considered expansion capital expenditures, not considered maintenance capital expenditures.capital. 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. In a contango market (oil prices for future deliveries are higher than for current deliveries), we use our tankage to improve our gathering margins by storing crude oil we have purchased at lower prices in the current month for delivery at higher prices in future months. In a backwardated market (oil prices for future deliveries are lower than for current deliveries), we use and lease less storage capacity, but increased marketing margins (premiums for prompt delivery) provide an offset to this reduced cash flow. We believe that the combination of our terminalling and storage activities and gathering and marketing activities provides a counter-cyclical balance that has a stabilizing effect on our operations and cash flow. The following table reflects our



              results of operationscertain financial data for each segment for the periods indicated (note that each of the items in the following table exclude depreciation and amortization):indicated.

                               
                Transportation  Facilities  Marketing  Total 
                (In millions) 
               
              Twelve Months Ended December 31, 2006
              		                
              Revenues:                
              External Customers (includes buy/sell revenues of $0, $0, and $4,761.9, respectively)(1) $343.6  $40.9  $22,059.9  $22,444.4 
              Intersegment(2)  190.4   46.8   0.9   238.1 
                               
              Total revenues of reportable segments $534.0  $87.7  $22,060.8  $22,682.5 
                               
              Equity in earnings of unconsolidated entities $1.9  $5.8  $—  $7.7 
                               
              Segment profit(1)(3)(4) $200.2  $34.6  $228.0  $462.8 
                               
              Capital expenditures $1,956.9  $1,323.6  $72.6  $3,353.1 
                               
              Total assets $3,792.9  $1,333.0  $3,589.0  $8,714.9 
                               
              SFAS 133 impact(1) $—  $—  $(4.4) $(4.4)
                               
              Maintenance capital $20.0  $4.9  $3.3  $28.2 
                               
              Twelve Months Ended December 31, 2005
              		                
              Revenues:                
              External Customers (includes buy/sell revenues of $0, $0, and $16,274.9, respectively)(1) $270.2  $14.2  $30,892.1  $31,176.5 
              Intersegment(2)  165.0   27.7   0.9   193.6 
                               
              Total revenues of reportable segments $435.2  $41.9  $30,893.0  $31,370.1 
                               
              Equity in earnings of unconsolidated entities $0.8  $1.0  $—  $1.8 
                               
              Segment profit(1)(3)(4) $169.5  $15.2  $175.4  $360.1 
                               
              Capital expenditures $108.5  $70.5  $15.1  $194.1 
                               
              Total assets $1,858.8  $142.5  $2,119.0  $4,120.3 
                               
              SFAS 133 impact(1) $—  $—  $(18.9) $(18.9)
                               
              Maintenance capital $8.5  $1.1  $4.4  $14.0 
                               
              Twelve Months Ended December 31, 2004
              		                
              Revenues:                
              External Customers (includes buy/sell revenues of $0, $0, and $11,396.8, respectively)(1) $214.2  $11.1  $20,749.7  $20,975.0 
              Intersegment(2)  134.7   22.8   1.0   158.5 
                               
              Total revenues of reportable segments $348.9  $33.9  $20,750.7  $21,133.5 
                               
              Equity in earnings of unconsolidated entities $0.5  $—  $—  $0.5 
                               
              Segment profit(1)(3)(4) $149.9  $18.2  $80.6  $248.7 
                               
              Capital expenditures $522.3  $89.3  $40.6  $652.2 
                               
              Total assets $1,646.9  $104.4  $1,409.1  $3,160.4 
                               
              SFAS 133 impact(1) $—  $—  $1.0  $1.0 
                               
              Maintenance capital $7.7  $2.0  $1.6  $11.3 
                               

               
              		 Pipeline
              		 Gathering
              Marketing,
              Terminalling
              & Storage
              		 Total
               
              		 (in millions)

              Twelve Months Ended December 31, 2003         
              Revenues:         
               External Customers $605.1 $11,984.7 $12,589.8
               Intersegment(a)  53.5  0.9  54.5
                
              		 
              		 
                Total revenues of reportable segments $658.6 $11,985.6 $12,644.3
                
              		 
              		 
              Segment profit(c) $81.3 $63.1 $144.4
                
              		 
              		 
              Capital expenditures $211.9 $21.9 $233.8
              Total assets $1,221.0 $874.6 $2,095.6
              Non-cash SFAS 133 impact(b) $— $0.4 $0.4
              Maintenance capital $6.4 $1.2 $7.6

              Twelve Months Ended December 31, 2002
               
               
               
               
               
               
               
               
               
              Revenues:         
               External Customers $462.4 $7,921.8 $8,384.2
               Intersegment(a)  23.8  —  23.8
                
              		 
              		 
                Total revenues of reportable segments $486.2 $7,921.8 $8,408.0
                
              		 
              		 
              Segment profit(c) $70.7 $58.9 $129.6
                
              		 
              		 
              Capital expenditures $341.9 $23.3 $365.2
              Total assets $1,030.7 $635.9 $1,666.6
              Non-cash SFAS 133 impact(b) $— $0.3 $0.3
              Maintenance capital $3.4 $2.6 $6.0

              Twelve Months Ended December 31, 2001
               
               
               
               
               
               
               
               
               
              Revenues:         
               External Customers $339.9 $6,528.3 $6,868.2
               Intersegment(a)  17.5  —  17.5
                
              		 
              		 
                Total revenues of reportable segments $357.4 $6,528.3 $6,885.7
                
              		 
              		 
              Segment profit(c) $58.9 $42.5 $101.4
                
              		 
              		 
              Capital expenditures $169.8 $80.4 $250.2
              Total assets $472.3 $788.9 $1,261.2
              Non-cash SFAS 133 impact(b) $— $0.2 $0.2
              Maintenance capital $0.5 $2.9 $3.4


              F-53

              (a)
              Intersegment sales were conducted at arms length.

              Table continued on following page


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

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

               
              		 For the year ended December 31,
              		 
               
              		 2003
              		 2002
              		 2001
              		 
              Segment profit $144.4 $129.6 $101.4 
              Unallocated general and administrative expenses  —  (1.0) (5.7)
              Depreciation and amortization  (46.8) (34.1) (24.3)
              Gain on sale of assets  0.6  —  1.0 
              Interest expense  (35.2) (29.1) (29.1)
              Interest income and other, net  (3.6) (0.1) 0.4 
              Cumulative effect of accounting change  —  —  0.5 
                
              		 
              		 
              		 
              Net Income $59.4 $65.3 $44.2 
                
              		 
              		 
              		 
              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

              (1)Amounts related to SFAS 133 are included in marketing revenues and impact segment profit.
              (2)Intersegment sales are conducted at arms length.
              (3)Marketing segment profit includes interest expense on contango inventory purchases of $49.2 million, $23.7 million, and $2.0 million for the twelve months ended December 31, 2006, 2005 and 2004, respectively.
              (4)The following table reconciles segment profit to consolidated income before cumulative effect of change in accounting principle (in millions):
                           
                Year Ended December 31, 
                2006  2005  2004 
               
              Segment profit $462.8  $360.1  $248.7 
              Depreciation and amortization  (100.4)  (83.5)  (68.7)
              Interest expense  (85.6)  (59.4)  (46.7)
              Interest income and other, net  2.0   0.6   (0.2)
                           
              Income before cumulative effect of change in accounting principle $278.8  $217.8  $133.1 
                           
              Geographic Data

              We have operations in the United States and Canada. Set forth below are revenues and long lived assets attributable to these geographic areas (in millions):

               
              		 For the Year Ended December 31,
              Revenues
               2003
              		 2002
              United States $10,536.8 $6,941.7
              Canada  2,053.0  1,442.5
                
              		 
                $12,589.8 $8,384.2
                
              		 

               

               
              For the Year Ended December 31,
              Long-Lived Assets
               2003
              		 2002
              United States $1,039.8 $866.9
              Canada  316.9  194.1
                
              		 
                $1,356.7 $1,061.0
                
              		 

              Note 16—Subsequent Events (Unaudited)
                           
                For the Year Ended December 31, 
                2006  2005  2004 
               
              Revenues
              		            
              United States (includes buy/sell revenues of $4,169.5, $14,749.0, and $10,164.6, respectively) $18,118.0  $26,198.9  $17,499.0 
              Canada (includes buy/sell revenues of $592.4, $1,525.9, and $1,232.2, respectively)  4,326.4   4,977.6   3,476.0 
                           
                $22,444.4  $31,176.5  $20,975.0 
                           

                       
                For the Year Ended
              		 
                December 31, 
                2006  2005 
               
              Long-Lived Assets
              		        
              United States $4,947.9  $1,887.0 
              Canada  600.4   422.5 
                       
                $5,548.3  $2,309.5 
                       

                      Link Acquisition.    On April 1, 2004, we completed the acquisition of substantially all of the North American crude oil and pipeline operations of Link Energy LLC ("Link") for approximately $330 million, including $273 million of cash, the assumption of $49 million of liabilities and $8 million of transaction, closing and integration costs and other items. The Link crude oil business consists of approximately 7,000 miles of active crude oil pipeline and gathering systems, over 10 million barrels of crude oil storage capacity, a fleet of approximately 200 owned or leased trucks and approximately 2 million barrels of crude oil linefill and working inventory. The Link assets complement our assets in West Texas and along the Gulf Coast and allow us to expand our presence in the Rocky Mountain and Oklahoma/Kansas regions.
              F-54

                      The acquisition was funded with cash on hand, borrowings under a new $200 million 364-day credit facility and borrowings under our existing revolving credit facilities. The new credit facility contains a twelve-month term out option, exercisable at our election, at the end of the primary term, bears interest at a rate of LIBOR plus a margin ranging from ..625% to 1.25%, depending upon our credit rating, and includes essentially the same covenants as our existing credit facilities. On April 15, we



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

                      On April 2, 2004, the Office of the Attorney General of Texas delivered written notice to us that it was investigating the possibility that the acquisition of Link's assets might reduce competition in one or more markets within the petroleum products industry in the State of Texas. In connection with the Link purchase, both PAA and Link completed all necessary filings required under the Hart-Scott-Rodino Act, and the required 30-day waiting period expired on March 24, 2004 without any inquiry or request for additional information from the U.S. Department of Justice or the Federal Trade Commission. Representatives from the Antitrust and Civil Medicaid Fraud Division of the Office of the Attorney General of Texas indicated their investigation was prompted by complaints received from allegedly interested industry parties regarding the potential impact on competition in the Permian Basin area of West Texas. We understand that similar complaints have been received by the Federal Trade Commission, and that, consistent with federal-state protocols for conducting joint merger investigations, appropriate federal and state antitrust authorities are coordinating their activities. We are cooperating fully with the antitrust enforcement authorities.EXHIBIT INDEX
                     
               3.1 — Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P., dated as of June 27, 2001 (incorporated by reference to Exhibit 3.1 toForm 8-K filed August 27, 2001).
               3.2 — Amendment No. 1 dated as of April 15, 2004 to the Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
               3.3 — Third Amended and Restated Agreement of Limited Partnership of Plains Marketing, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.2 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
               3.4 — Third Amended and Restated Agreement of Limited Partnership of Plains Pipeline, L.P. dated as of April 1, 2004 (incorporated by reference to Exhibit 3.3 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
               3.5 — Certificate of Incorporation of PAA Finance Corp. (incorporated by reference to Exhibit 3.6 to the Registration Statement onForm S-3 filed August 27, 2001).
               3.6 — Bylaws of PAA Finance Corp. (incorporated by reference to Exhibit 3.7 to the Registration Statement onForm S-3 filed August 27, 2001).
               3.7 — Second Amended and Restated Limited Liability Company Agreement of Plains All American GP LLC, dated September 12, 2005 (incorporated by reference to Exhibit 3.1 to the Current Report onForm 8-K filed September 16, 2005).
               3.8 — Second Amended and Restated Limited Partnership Agreement of Plains AAP, L.P., dated September 12, 2005 (incorporated by reference to Exhibit 3.2 to the Current Report onForm 8-K filed September 16, 2005).
               3.9 — Amendment No. 2 dated November 15, 2006 to Third Amended and Restated Agreement of Limited Partnership of Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 3.1 to the Current Report onForm 8-K filed November 21, 2006).
               3.10† — Certificate of Incorporation of Pacific Energy Finance Corporation.
               3.11† — Bylaws of Pacific Energy Finance Corporation.
               4.1 — Indenture dated September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp. and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.1 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2002).
               4.2 — First Supplemental Indenture (Series A and Series B 7.75% Senior Notes due 2012) dated as of September 25, 2002 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.2 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2002).
               4.3 — Second Supplemental Indenture (Series A and Series B 5.625% Senior Notes due 2013) dated as of December 10, 2003 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.4 to the Annual Report onForm 10-K for the year ended December 31, 2003).
               4.4 — Third Supplemental Indenture (Series A and Series B 4.75% Senior Notes due 2009) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.4 to the Registration Statement onForm S-4, FileNo. 333-121168).
               4.5 — Fourth Supplemental Indenture (Series A and Series B 5.875% Senior Notes due 2016) dated August 12, 2004 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.5 to the Registration Statement onForm S-4, FileNo. 333-121168).
               4.6 — Class C Common Unit Purchase Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income Partners, L.P., Kayne Anderson MLP Fund, L.L.P., Tortoise Energy Infrastructure Corporation and Vulcan Energy II Inc. dated March 31, 2004 (incorporated by reference to Exhibit 4.2 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).
               4.7 — Registration Rights Agreement by and among Plains All American Pipeline, L.P., Kayne Anderson Energy Fund II, L.P., KAFU Holdings, L.P., Kayne Anderson Capital Income Partners (QP), L.P., Kayne Anderson MLP Fund, L.P., Tortoise Energy Infrastructure Corporation and Vulcan Energy II Inc. dated April 15, 2004 (incorporated by reference to Exhibit 4.1 to the Quarterly Report onForm 10-Q for the quarter ended March 31, 2004).


                     
               4.8 — Fifth Supplemental Indenture (Series A and Series B 5.25% Senior Notes due 2015) dated May 27, 2005 among Plains All American Pipeline, L.P., PAA Finance Corp., the Subsidiary Guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed May 31, 2005).
               4.9 — Sixth Supplemental Indenture (Series A and Series B 6.70% Senior Notes due 2036) dated as of May 12, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp. and subsidiary guarantors signatory thereto and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed May 12, 2006).
               4.10 — Seventh Supplemental Indenture, dated as of May 12, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains LPG Services GP LLC, Plains LPG Services, L.P. and Lone Star Trucking, LLC and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report onForm 8-K filed May 12, 2006).
               4.11 — Eighth Supplemental Indenture, dated as of August 25, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing International GP LLC, Plains Marketing International, L.P. and Plains LPG Marketing, L.P. and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed August 25, 2006).
               4.12 — Ninth Supplemental Indenture (Series A and Series B 6.125% Senior Notes due 2017), dated as of October 30, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp. and subsidiary guarantors signatory thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed October 30, 2006).
               4.13 — Tenth Supplemental Indenture (Series A and Series B 6.650% Senior Notes due 2037), dated as of October 30, 2006, to Indenture, dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp. and subsidiary guarantors signatory thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report onForm 8-K filed October 30, 2006).
               4.14 — Eleventh Supplemental Indenture dated November 15, 2006 to Indenture dated as of September 25, 2002, among Plains All American Pipeline, L.P., PAA Finance Corp., PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Pacific Energy Finance Corporation, Rangeland Marketing Company and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K filed November 21, 2006).
               4.15 — Indenture dated June 16, 2004 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 71/8% senior notes due 2014 (incorporated by reference to Exhibit 4.21 to Pacific’s Quarterly Report onForm 10-Q for the quarter ended June 30, 2004).
               4.16 — First Supplemental Indenture dated March 3, 2005 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 71/8% senior notes due 2014 (incorporated by reference to Exhibit 4.1 to Pacific’s Current Report onForm 8-K filed March 9, 2005).
               4.17† — Second Supplemental Indenture dated September 23, 2005 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 71/8% senior notes due 2014.



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              PLAINS ALL AMERICAN PIPELINE, L.P. FORM 10-K/A—2003 ANNUAL REPORT
              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FORM 10-K/A—2003 ANNUAL REPORT Table of Contents
              FORWARD-LOOKING STATEMENTS
              PART I
              PART II
              PART III
              PART IV
              SIGNATURES
              PLAINS ALL AMERICAN PIPELINE, L.P. INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS
              Report of Independent Registered Public Accounting Firm
              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except unit data)
              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per unit data)
              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL (in thousands)
              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
              CONSOLIDATED STATEMENT OF CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

                     
               4.18 — Third Supplemental Indenture dated November 15, 2006 to Indenture dated as of June 16, 2004, among Plains All American Pipeline, L.P., Pacific Energy Finance Corporation, PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Rangeland Marketing Company, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, Plains Marketing Canada, L.P., PMC (Nova Scotia) Company, Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains Marketing International L.P., Plains LPG Marketing, L.P., PAA Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report onForm 8-K filed November 21, 2006).
               4.19 — Indenture dated September 23, 2005 among Pacific Energy Partners, L.P. and Pacific Energy Finance Corporation, the guarantors named therein, and Wells Fargo Bank, National Association, as trustee of the 61/4% senior notes due 2015 (incorporated by reference to Exhibit 4.1 to Pacific’s Current Report onForm 8-K filed September 28, 2005).
               4.20 — First Supplemental Indenture dated November 15, 2006 to Indenture dated as of September 23, 2005, among Plains All American Pipeline, L.P., Pacific Energy Finance Corporation, PEG Canada GP LLC, Pacific Energy Group LLC, PEG Canada, L.P., Pacific Marketing and Transportation LLC, Rocky Mountain Pipeline System LLC, Ranch Pipeline LLC, Pacific Atlantic Terminals LLC, Pacific L.A. Marine Terminal LLC, Rangeland Pipeline Company, Aurora Pipeline Company Ltd., Rangeland Pipeline Partnership, Rangeland Northern Pipeline Company, Rangeland Marketing Company, Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, Plains Marketing Canada, L.P., PMC (Nova Scotia) Company, Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains Marketing International L.P., Plains LPG Marketing, L.P., PAA Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Current Report onForm 8-K filed November 21, 2006).
               4.21 — Registration Rights Agreement dated as of July 26, 2006 among Plains All American Pipeline, L.P., Vulcan Capital Private Equity I LLC, Kayne Anderson MLP Investment Company and Kayne Anderson Energy Total Return Fund, Inc. (incorporated by reference to Exhibit 4.13 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2006).
               4.22 — Registration Rights Agreement dated as of December 19, 2006 among Plains All American Pipeline, L.P.,E-Holdings III, L.P.,E-Holdings V, L.P., Kayne Anderson MLP Investment Company and Kayne Anderson Energy Development Company (incorporated by reference to Exhibit 4.6 to the Registration Statement onForm S-3/A, File No,333-138888).
               4.23 — Exchange and Registration Rights Agreement dated as of October 30, 2006, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains LPG Marketing, L.P., Plains Marketing International, L.P., Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, BNP Paribas Securities Corp., SunTrust Capital Markets, Inc., Fortis Securities LLC, Scotia Capital (USA) Inc., Comerica Securities, Inc., Commerzbank Capital Markets Corp., Daiwa Securities America Inc., DnB NOR Markets, Inc., HSBC Securities (USA) Inc., ING Financial Markets LLC, Mitsubishi UFJ Securities International plc, Piper Jaffray & Co., RBC Capital Markets Corporation, SG Americas Securities, LLC, Wedbush Morgan Securities Inc. and Wells Fargo Securities, LLC relating to the 2017 Notes (incorporated by reference to Exhibit 4.3 to the Current Report onForm 8-K filed October 30, 2006).

                     
               4.24 — Exchange and Registration Rights Agreement dated as of October 30, 2006, among Plains All American Pipeline, L.P., PAA Finance Corp., Plains Marketing, L.P., Plains Pipeline, L.P., Plains Marketing GP Inc., Plains Marketing Canada LLC, PMC (Nova Scotia) Company, Plains Marketing Canada, L.P., Basin Holdings GP LLC, Basin Pipeline Holdings, L.P., Rancho Holdings GP LLC, Rancho Pipeline Holdings, L.P., Plains LPG Services GP LLC, Plains LPG Services, L.P., Lone Star Trucking, LLC, Plains Marketing International GP LLC, Plains LPG Marketing, L.P., Plains Marketing International, L.P., Citigroup Global Markets Inc., UBS Securities LLC, Banc of America Securities LLC, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, BNP Paribas Securities Corp., SunTrust Capital Markets, Inc., Fortis Securities LLC, Scotia Capital (USA) Inc., Comerica Securities, Inc., Commerzbank Capital Markets Corp., Daiwa Securities America Inc., DnB NOR Markets, Inc., HSBC Securities (USA) Inc., ING Financial Markets LLC, Mitsubishi UFJ Securities International plc, Piper Jaffray & Co., RBC Capital Markets Corporation, SG Americas Securities Inc. and Wells Fargo Securities, LLC relating to the 2037 Notes (incorporated by reference to Exhibit 4.4 to the Current Report onForm 8-K filed October 30, 2006).
               10.1 — Second Amended and Restated Credit Agreement dated as of July 31, 2006 by and among Plains All American Pipeline, L.P., as US Borrower; PMC (Nova Scotia) Company and Plains Marketing Canada, L.P., as Canadian Borrowers; Bank of America, N.A., as Administrative Agent; Bank of America, N.A., acting through its Canada Branch, as Canadian Administrative Agent; Wachovia Bank, National Association and JPMorgan Chase Bank, N.A., asCo-Syndication Agents; Fortis Capital Corp., Citibank, N.A., BNP Paribas, UBS Securities LLC, SunTrust Bank, and The Bank of Nova Scotia, as Co-Documentation Agents; the Lenders party thereto; and Banc of America Securities LLC and Wachovia Capital Markets, LLC , as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed August 4, 2006).
               10.2 — Restated Credit Facility (Uncommitted Senior Secured Discretionary Contango Facility) dated November 19, 2004 among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed November 24, 2004).
               10.3 — Amended and Restated Crude Oil Marketing Agreement, dated as of July 23, 2004, among Plains Resources Inc., Calumet Florida Inc. and Plains Marketing, L.P. (incorporated by reference to Exhibit 10.2 to the Quarterly Report onForm 10-Q for the quarter ended June 30, 2004).
               10.4 — Amended and Restated Omnibus Agreement, dated as of July 23, 2004, among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., Plains Pipeline, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Quarterly Report onForm 10-Q for the quarter ended June 30, 2004).
               10.5 — Contribution, Assignment and Amendment Agreement, dated as of June 27, 2001, among Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., Plains AAP, L.P., Plains All American GP LLC and Plains Marketing GP Inc. (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed June 27, 2001).
               10.6 — Contribution, Assignment and Amendment Agreement, dated as of June 8, 2001, among Plains All American Inc., Plains AAP, L.P. and Plains All American GP LLC (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed June 11, 2001).
               10.7 — Separation Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc., Plains All American GP LLC, Plains AAP, L.P. and Plains All American Pipeline, L.P. (incorporated by reference to Exhibit 10.2 to the Current Report onForm 8-K filed June 11, 2001).
               10.8** — Pension and Employee Benefits Assumption and Transition Agreement, dated as of June 8, 2001 among Plains Resources Inc., Plains All American Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Current Report onForm 8-K filed June 11, 2001).
               10.9** — Plains All American GP LLC 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed January 26, 2005).
               10.10** — Plains All American GP LLC 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1 to Registration Statement onForm S-8, FileNo. 333-74920) as amended June 27, 2003 (incorporated by reference to Exhibit 10.1 to the Quarterly Report onForm 10-Q for the quarter ended June 30, 2003).
               10.11** — Plains All American 2001 Performance Option Plan (incorporated by reference to Exhibit 99.2 to the Registration Statement onForm S-8, FileNo. 333-74920).

                     
               10.12** — Amended and Restated Employment Agreement between Plains All American GP LLC and Greg L. Armstrong dated as of June 30, 2001 (incorporated by reference to Exhibit 10.1 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2001).
               10.13** — Amended and Restated Employment Agreement between Plains All American GP LLC and Harry N. Pefanis dated as of June 30, 2001 (incorporated by reference to Exhibit 10.2 to the Quarterly Report onForm 10-Q for the quarter ended September 30, 2001).
               10.14 — Asset Purchase and Sale Agreement dated February 28, 2001 between Murphy Oil Company Ltd. and Plains Marketing Canada, L.P. (incorporated by reference to Exhibit 99.1 to the Current Report onForm 8-K filed May 10, 2001).
               10.15 — Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to the Registration Statement onForm S-1, FileNo. 333-64107).
               10.16 — Transportation Agreement dated August 2, 1993, among All American Pipeline Company, Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to the Registration Statement onForm S-1, FileNo. 333-64107).
               10.17 — First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to the Annual Report onForm 10-K for the year ended December 31, 1998).
               10.18 — Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.16 to the Annual Report onForm 10-K for the year ended December 31, 1998).
               10.19** — Plains All American Inc. 1998 Management Incentive Plan (incorporated by reference to Exhibit 10.5 to the Annual Report onForm 10-K for the year ended December 31, 1998).
               10.20** — PMC (Nova Scotia) Company Bonus Program (incorporated by reference to Exhibit 10.20 to the Annual Report onForm 10-K for the year ended December 31, 2004).
               10.21** — Quarterly Bonus Summary (incorporated by reference to Exhibit 10.21 to the Annual Report onForm 10-K for the year ended December 31, 2005).
               10.22**† — Directors’ Compensation Summary.
               10.23 — Master Railcar Leasing Agreement dated as of May 25, 1998 (effective June 1, 1998), between Pivotal Enterprises Corporation and CANPET Energy Group, Inc., (incorporated by reference to Exhibit 10.16 to the Annual Report onForm 10-K for the year ended December 31, 2001).
               10.24** — Form of LTIP Grant Letter (Armstrong/Pefanis) (incorporated by reference to Exhibit 10.24 to the Annual Report onForm 10-K for the year ended December 31, 2005).
               10.25** — Form of LTIP Grant Letter (executive officers) (incorporated by reference to Exhibit 10.3 to the Current Report onForm 8-K filed April 1, 2005).
               10.26** — Form of LTIP Grant Letter (independent directors) (incorporated by reference to Exhibit 10.3 to the Current Report onForm 8-K filed February 23, 2005).
               10.27** — Form of LTIP Grant Letter (designated directors) (incorporated by reference to Exhibit 10.4 to the Current Report onForm 8-K filed February 23, 2005).
               10.28** — Form of LTIP Grant Letter (payment to entity) (incorporated by reference to Exhibit 10.5 to the Current Report onForm 8-K filed February 23, 2005).
               10.29** — Form of Option Grant Letter (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed April 1, 2005).
               10.30 — Administrative Services Agreement between Plains All American Pipeline Company and Vulcan Energy Corporation, dated October 14, 2005 (incorporated by reference to Exhibit 1.1 to the Current Report onForm 8-K filed October 19, 2005).
               10.31 — Amended and Restated Limited Liability Company Agreement of PAA/Vulcan Gas Storage, LLC, dated September 13, 2005 (incorporated by reference to Exhibit 1.1 to the Current Report onForm 8-K filed September 19, 2005).
               10.32 — Membership Interest Purchase Agreement by and between Sempra Energy Trading Corp. and PAA/Vulcan Gas Storage, LLC, dated August 19, 2005 (incorporated by reference to Exhibit 1.2 to the Current Report onForm 8-K filed September 19, 2005).
               10.33** — Waiver Agreement dated as of August 12, 2005 between Plains All American GP LLC and Greg L. Armstrong (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed August 16, 2005).

                     
               10.34** — Waiver Agreement dated as of August 12, 2005 between Plains All American GP LLC and Harry N. Pefanis (incorporated by reference to Exhibit 10.2 to the Current Report onForm 8-K filed August 16, 2005).
               10.35 — Excess Voting Rights Agreement dated as of August 12, 2005 between Vulcan Energy GP Holdings Inc. and Plains All American GP LLC (incorporated by reference to Exhibit 10.3 to the Current Report onForm 8-K filed August 16, 2005).
               10.36 — Excess Voting Rights Agreement dated as of August 12, 2005 between Lynx Holdings I, LLC and Plains All American GP LLC (incorporated by reference to Exhibit 10.4 to the Current Report onForm 8-K filed August 16, 2005).
               10.37 — First Amendment dated as of April 20, 2005 to Restated Credit Agreement, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed April 21, 2005).
               10.38 — Second Amendment dated as of May 20, 2005 to Restated Credit Agreement, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed May 12, 2005).
               10.39** — Form of LTIP Grant Letter (executive officers) (incorporated by reference to Exhibit 10.39 to the Annual Report onForm 10-K for the year ended December 31, 2005).
               10.40** — Employment Agreement between Plains All American GP LLC and John vonBerg dated December 18, 2001 (incorporated by reference to Exhibit 10.40 to the Annual Report onForm 10-K for the year ended December 31, 2005).
               10.41 — Third Amendment dated as of November 4, 2005 to Restated Credit Agreement, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.41 to the Annual Report onForm 10-K for the year ended December 31, 2005).
               10.42† — Fourth Amendment dated as of November 16, 2006 to Restated Credit Agreement, by and among Plains Marketing, L.P., Bank of America, N.A., as Administrative Agent, and the Lenders party thereto.
               10.43 — First Amendment dated May 9, 2006 to the Amended and Restated Limited Liability Company Agreement of PAA/Vulcan Gas Storage, LLC dated September 13, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed May 15, 2006).
               10.44** — Form of LTIP Grant Letter (audit committee members) (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K filed August 23, 2006).
               10.45†** — Plains All American PPX Successor Long-Term Incentive Plan.
               10.46 — Interim364-Day Credit Agreement dated as of July 31, 2006 by and among Plains All American Pipeline, L.P., as Borrower; JPMorgan Chase Bank, N.A., as Administrative Agent; Bank of America, N.A. and Citibank, N.A., as Co-Syndication Agents; Wachovia Bank, National Association and UBS Securities LLC, as Co-Documentation Agents; the Lenders party thereto; and JPMorgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers (incorporated by reference to Exhibit 10.2 to the Current Report onForm 8-K filed August 4, 2006).
               10.47** — Forms of LTIP Grant Letters (executive officers) — February 2007 awards (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed February 28, 2007).
               21.1† — List of Subsidiaries of Plains All American Pipeline, L.P.
               23.1† — Consent of PricewaterhouseCoopers LLP.
               31.1† — Certification of Principal Executive Officer pursuant to Exchange ActRules 13a-14(a) and15d-14(a).
               31.2† — Certification of Principal Financial Officer pursuant to Exchange ActRules 13a-14(a) and15d-14(a).
               32.1† — Certification of Principal Executive Officer pursuant to 18 USC 1350.
               32.2† — Certification of Principal Financial Officer pursuant to 18 USC 1350.
              †Filed herewith
              **Management compensatory plan or arrangement