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

                                   FORM 10-K

           [X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                        SECURITIES EXCHANGE ACT OF 1934

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000

                                       OR

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

                        COMMISSION FILE NUMBER: 1-14569

                       PLAINS ALL AMERICAN PIPELINE, L.P.

             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

           DELAWARE                                   76-0582150
(STATE OR OTHER JURISDICTION OF                     (I.R.S. EMPLOYER
 INCORPORATION OR ORGANIZATION)                     IDENTIFICATION NO.)

                               500 DALLAS STREET
                              HOUSTON, TEXAS 77002
                    (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
                                   (ZIP CODE)

                                 (713) 654-1414
              (REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)

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

    TITLE OF EACH CLASS        NAME OF EACH EXCHANGE ON WHICH REGISTERED
    -------------------        -----------------------------------------
       COMMON UNITS                      NEW YORK STOCK EXCHANGE

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  [X]    No

The aggregate value of the Common Units held by non-affiliates of the registrant
(treating all executive officers and directors of the registrant, for this
purpose, as if they may be affiliates of the registrant) was approximately
$521,861,243 on March 22, 2001, based on $22.80 per unit, the closing price of
the Common Units as reported on the New York Stock Exchange on such date.

At March 22, 2001, there were outstanding 23,049,239 Common Units, 1,307,190
Class B Common Units and 10,029,619 Subordinated Units.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.  [X]

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              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
                          2000 FORM 10-K ANNUAL REPORT
                               TABLE OF CONTENTS

                                                                         PAGE
                                                                         ----
                                     Part I

Items 1. and 2.  Business and Properties...............................    3
Item 3.          Legal Proceedings.....................................   22
Item 4.          Submission of Matters to a Vote of Security Holders...   23

                                    PART II

Item 5.          Market for Registrant's Common Units and Related
                 Unitholder Matters....................................   23
Item 6.          Selected Financial and Operating Data.................   24
Item 7.          Management's Discussion and Analysis of Financial
                 Condition and Results of Operations...................   27
Item 7a.         Quantitative and Qualitative Disclosures About
                 Market Risks..........................................   37
Item 8.          Financial Statements and Supplementary Data...........   38
Item 9.          Changes in and Disagreements with Accountants on
                 Accounting and Financial Disclosure...................   38

                                    PART III

Item 10.         Directors and Executive Officers of Our General
                 Partner...............................................   39
Item 11.         Executive Compensation................................   41
Item 12.         Security Ownership of Certain Beneficial Owners and
                 Management............................................   44
Item 13.         Certain Relationships and Related Transactions........   44

                                    PART IV

Item 14.         Exhibits, Financial Statement Schedules and Reports
                 on Form 8-K...........................................   47

                           FORWARD-LOOKING STATEMENTS

  All statements, 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" and "forecast" and similar expressions and statements
regarding our business strategy, plans and objectives of our management for
future operations. These statements reflect our current views and those of our
general partner with respect to future events, based on what we believe are
reasonable assumptions. These statements, however, are subject to certain risks,
uncertainties and assumptions, including, but not limited to:

  .  the availability of adequate supplies of and demand for crude oil in the
     areas in which we operate;
  .  the impact of crude oil price fluctuations;
  .  the effects of competition;
  .  the success of our risk management activities;
  .  the availability (or lack thereof) of acquisition or combination
     opportunities;
  .  the impact of current and future laws and governmental regulations;
  .  environmental liabilities that are not covered by an indemnity or
     insurance;
  .  fluctuations in the debt and equity markets; and
  .  general economic, market or business conditions.

If one or more of these risks or uncertainties materialize, or if underlying
assumptions prove incorrect, actual results may vary materially from the results
anticipated in the forward-looking statements. Except as required by applicable
securities laws, we do not intend to update these forward-looking statements and
information.

                                       2

                                     PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

  We are a publicly traded Delaware limited partnership engaged in interstate
and intrastate marketing, transportation and terminalling of crude oil. We were
formed in September 1998 to acquire and operate the midstream crude oil business
and assets of Plains Resources Inc. ("Plains Resources"), whose wholly owned
subsidiary, Plains All American, Inc., is our general partner.

  Our operations are concentrated in California, Texas, Oklahoma, Louisiana,
Illinois and the Gulf of Mexico and can be categorized into two primary business
activities:

  .  CRUDE OIL PIPELINE TRANSPORTATION. Our activities from pipeline operations
     generally consist of transporting third-party volumes of crude oil for a
     tariff, as well as merchant activities designed to capture location and
     quality price differentials. We own and operate several pipeline systems
     including:

     .  a segment of the All American Pipeline that extends approximately 140
        miles from Las Flores, California to Emidio, California;
     .  the San Joaquin Valley Gathering System in California;
     .  the West Texas Gathering System, the Spraberry Pipeline System, and the
        East Texas Pipeline System, which are all located in Texas;
     .  the Sabine Pass Pipeline System in southwest Louisiana and southeast
        Texas;
     .  the Ferriday Pipeline System in eastern Louisiana and western
        Mississippi; and
     .  the Illinois Basin Pipeline System in southern Illinois.

  .  TERMINALLING AND STORAGE ACTIVITIES AND GATHERING AND MARKETING ACTIVITIES.
     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". We own and operate a state-of-the-art,
     3.1 million barrel, above-ground crude oil terminalling and storage
     facility at Cushing, Oklahoma, the largest crude oil trading hub in the
     United States and the designated delivery point for New York Mercantile
     Exchange ("NYMEX") crude oil futures contracts. We also have an additional
     6.7 million barrels of terminalling and storage capacity in our other
     facilities, including tankage associated with our pipeline and gathering
     systems. Our terminalling and storage operations generate revenue 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 or pipelines; and
     .  the subsequent resale or exchange of crude oil at various points along
        the crude oil distribution chain.

  Consistent with our publicly announced intention to expand operations into
Canada, we are pursuing the acquisition of certain Canadian assets in two
separate transactions for aggregate consideration of approximately $200.0
million. See "Acquisitions and Dispositions".

PARTNERSHIP STRUCTURE AND MANAGEMENT

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

  Our general partner has sole responsibility for conducting our business and
managing our operations and owns all of the incentive distribution rights. See
Item 13. - "Certain Relationships and Related Transactions". Some of the senior
executives who currently manage our business also manage and operate the
business of Plains Resources. Our general partner does not receive any
management fee or other compensation in connection with its management of our
business, but it is reimbursed for all direct and indirect expenses incurred on
our behalf.

                                       3

  The chart below depicts the current organization and ownership of Plains All
American Pipeline, the operating partnerships and the subsidiaries. As is
reflected in the chart, a subsidiary of our general partner owns 6,791,816
common units and 10,029,619 subordinated units, representing a 19.4% and 28.6%
interest in the partnership and our subsidiaries. In addition, our general
partner owns 1,307,190 Class B common units representing a 3.7% interest in the
partnership and our subsidiaries. Except for the table inset, the percentages
reflected in the organization chart represent the approximate ownership interest
in Plains All American Pipeline, the operating partnerships and their
subsidiaries individually and not on a combined basis.

                             [CHART APPEARS HERE]

                                       4

UNAUTHORIZED TRADING LOSSES

 Background

  In November 1999, we discovered that a former employee had engaged in
unauthorized trading activity, resulting in losses of approximately $174.0
million, which includes estimated associated costs and legal expenses. 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 from March through November 1999, and the impact warranted a
restatement of previously reported financial information for 1999 and 1998.
Approximately $7.1 million of the unauthorized trading losses was recognized in
1998 and the remainder in 1999. In 2000, we recognized an additional $7.0
million charge for litigation related to the unauthorized trading losses.

  Normally, as we purchase crude oil, we establish a margin by selling crude oil
for physical delivery to third parties, or by entering into future delivery
obligations with respect to futures contracts. The employee in question violated
our policy of maintaining a substantially balanced position between purchases
and sales (or future delivery obligations) by negotiating one side of a
transaction without negotiating the other, leaving the position "open." The
trader concealed his activities by hiding open trading positions, by rolling
open positions forward using off-market, inter-month transactions, and by
providing to counter-parties forged documents that purported to authorize such
transactions. An "inter-month" transaction is one in which the receipt and
delivery of crude oil are scheduled in different months. An "off-market"
transaction is one in which the price is higher or lower than the prices
available in the market on the day of the transaction. By matching one side of
an inter-month transaction with an open position, and using off-market pricing
to match the pricing of the open position, the trader could present
documentation showing both a purchase and a sale, creating the impression of
compliance with our policy. The offsetting side of the inter-month transaction
became a new, hidden open position.

 Investigation; Enhancement of Procedures

  Upon discovery of the violation and related losses, we engaged an outside law
firm to lead the investigation of the unauthorized trading activities. The law
firm retained specialists from an independent accounting firm to assist in the
investigation. In parallel effort with the investigation mentioned above, the
role of the accounting-firm specialists was expanded to include reviewing and
making recommendations for enhancement of our systems, policies and procedures.
As a result, we have developed a new 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.

  The new policy was adopted by the Board of Directors of Plains All American
Inc. in May 2000; however, implementation of many of the procedures commenced in
January 2000, based on information developed throughout the investigation and
the review of the policies, processes and procedures. In March 2000, management
hired another independent accounting firm to provide additional objective input
regarding the processes and procedures, and to supplement management's efforts
to expedite the implementation of the enhanced policies and automation of the
processes and procedures. The procedures have now been implemented, although not
all reports are fully automated. The procedures have been, and will continue to
be, refined.

  To specifically address the methods used by the trader to conceal the
unauthorized trading, in January 2000 we sent a notice to each of our material
counter-parties that no person at Plains All American Pipeline, L.P. was
authorized to enter into off-market transactions. In addition, we have taken the
following actions:

  .  We have communicated our trading strategies and risk tolerance to our
     traders by more clearly and specifically defining those strategies and risk
     limits in our written procedures.
  .  The new procedures require (i) more comprehensive and frequent reporting
     that will allow our officials to evaluate risk positions in greater detail,
     and (ii) enhanced procedures to check compliance with these reporting
     requirements and to confirm that trading activity was conducted within
     guidelines.
  .  The procedures provide a system to educate each employee who is involved,
     directly or indirectly, in our crude oil transaction activities with
     respect to policies and procedures, and impose an obligation to notify the
     Risk Manager, (an independent function that reports directly to the Chief
     Financial Officer) directly of any questionable transactions or failure of
     others to adhere to the policies, practices and procedures.
  .  Finally, following notification to each of our material counter-parties
     that off-market trading is against our policy and that any written evidence
     to the contrary is unauthorized and false, the Risk Manager and our other
     representatives have also communicated our policies and enhanced procedures
     to our counter-parties to advise them of the information we will routinely
     require from them to assure timely recording and confirmation of trades.

                                       5

  We can give no assurance that the above steps will serve to detect and prevent
all violations of our trading policy; we believe, however, 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
before any material loss could develop.

 Effects of the Loss

  The unauthorized trading and associated losses resulted in a default of
certain covenants under our then-existing credit facilities and significant
short-term cash and letter of credit requirements.

  In December 1999, we executed amended credit facilities and obtained default
waivers from all of our lenders. We paid approximately $13.7 million to our
lenders in connection with the amended credit facilities. In connection with the
amendments, our general partner loaned us approximately $114.0 million.

  On May 8, 2000, we entered into new bank credit agreements to refinance our
existing bank debt and repay the $114.0 million owed to our general partner. The
new bank credit agreements also provided us with additional flexibility for
working capital, capital expenditures and other general corporate purposes. At
closing, we had $256.0 million outstanding under a $400.0 million senior secured
revolving credit facility. We also had at closing letters of credit of
approximately $173.8 million and borrowings of approximately $20.3 million
outstanding under a separate $300.0 million senior secured letter of credit and
borrowing facility. See Item 7. - "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources."

  In the period immediately following the disclosure of the unauthorized trading
losses, a significant number of our suppliers and trading partners reduced or
eliminated the open credit previously extended to us. Consequently, the amount
of letters of credit we needed to support the level of our crude oil purchases
then in effect increased significantly. In addition, the cost of letters of
credit increased under our credit facility. Some of our purchase contracts were
terminated. As a result of these changes, aggregate volumes purchased have
declined from an average of 528,000 barrels per day for the fiscal quarter
preceding the trading loss to an average of 302,000 barrels per day in the
fourth quarter of 2000. Approximately 72,000 barrels per day of the decrease is
related to barrels gathered at producer lease locations and 154,000 barrels per
day is attributable to bulk purchases. As a result of the increase in letter of
credit costs and reduced volumes, annual Adjusted EBITDA and net income for 2000
was adversely affected by approximately $6.0 million, excluding the positive
impact of current favorable market conditions. Adjusted EBITDA means earnings
before interest expense, income taxes, depreciation and amortization,
unauthorized trading losses, noncash compensation expense, restructuring
expense, gains on the sale of linefill and pipeline, allowance for accounts
receivable and extraordinary loss from extinguishment of debt.

  After the public announcement of the trading losses, class action lawsuits
were filed against us and Plains Resources. Derivative lawsuits have also been
filed in the United States District Court of the Southern District of Texas and
the Delaware Chancery Court, Newcastle County. We and Plains Resources reached
an agreement to settle all of the class actions and the Delaware derivative
action. See Item 3. - "Legal Proceedings".

RESULTS OF OPERATIONS

  For the year ended December 31, 2000, our Adjusted EBITDA, cash flow from
operations and net income totaled $103.0 million, $73.9 million and $77.5
million, respectively. Cash flow from operations represents net income before
noncash items. Cash flow from operations also excludes the unauthorized trading
losses, noncash compensation expense, gains on the sale of linefill and
pipeline, allowance for accounts receivable and extraordinary loss from
extinguishment of debt. Excluding the unauthorized trading losses, our gross
margin in 2000 was $134.7 million with our terminalling and storage activities
and gathering and marketing activities accounting for approximately 62% of our
gross margin and our pipeline operations accounting for approximately 38%.

ACQUISITIONS AND DISPOSITIONS

  Consistent with our publicly announced intention to expand operations into
Canada, we are pursuing the acquisition of certain Canadian assets in two
separate transactions for aggregate consideration of approximately $200.0
million. Set forth below is a brief description of the acquisitions.

                                       6

 Murphy Oil Company Ltd. Midstream Operations

  On March 1, 2001, we signed an agreement to purchase substantially all of the
crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil
Company Ltd. ("Murphy") for approximately $155.0 million in cash, plus an
additional cash payment, to be determined prior to closing in accordance with
the agreement, for excess inventory in the systems (estimated to be
approximately $5.0 million). The principal assets to be acquired include
approximately 450 miles of crude oil and condensate transmission mainlines and
associated gathering and lateral lines, and approximately 1.1 million barrels of
crude oil storage and terminalling capacity located primarily in Kerrobert,
Saskatchewan, approximately 200,000 barrels of linefill, as well as a currently
inactive 108-mile mainline system and 121 trailers used primarily for crude oil
transportation.

  Murphy has agreed to continue to transport production from fields currently
delivering crude oil to these pipeline systems, under a new long-term contract.
The current volume is approximately 11,000 barrels per day. The pipeline systems
transport approximately 200,000 barrels per day of light, medium and heavy
crudes, as well as condensate.

Certain of the principal assets include:

  .  Manito Pipeline - A 100% ownership interest in a 101-mile crude oil line
     and a parallel 101-mile condensate line that connects the North-
     Saskatchewan Pipeline and multiple gathering lines to the Enbridge system
     at Kerrobert, Saskatchewan. The Enbridge system is a 1.9 million barrel per
     day pipeline that transports liquid hydrocarbons from the oilfields of
     Western Canada to refineries and markets in Eastern Canada and the
     Midwestern U.S. The Manito line is located in the Canadian province of
     Saskatchewan near the Alberta border and has current throughput of
     approximately 80,000 barrels per day.
  .  Cactus Lake/Bodo Pipeline - Varying interests from 13.125% to 76.25% in a
     55-mile crude oil line and a parallel 55-mile condensate line, which
     connect to the terminal at Kerrobert. Current throughput approximates
     39,000 barrels per day.
  .  Milk River Pipeline - A 100% ownership in three parallel 11-mile lines
     connecting the Bow River Pipeline in Alberta to the Cenex Pipeline at the
     U.S. border. Current throughput approximates 90,000 barrels per day.

 Canadian Marketing Assets

  We have entered into a letter of intent to purchase the assets of a Canadian
marketing company. The expected purchase price is approximately $43.0 million,
of which approximately $18.0 million will be subject to certain performance
targets. The marketing company currently generates annual EBITDA of
approximately $10.0 million, gathering approximately 75,000 barrels per day of
crude oil and marketing approximately 26,000 barrels per day of natural gas
liquids. Tangible assets include a crude oil handling facility, a 100,000 barrel
tank facility and working capital of approximately $8.5 million.

  Initial financing for the acquisitions will be provided via an expansion of
our existing revolving credit, letter of credit and inventory facility. The
expanded facility will initially be underwritten by Fleet Boston and will
consist of a $100.0 million five-year term loan and a $30.0 million revolving
credit facility that will expire in April 2005. Consistent with our stated
policy of maintaining a strong capital structure by funding acquisitions with a
balance of debt and equity, we intend to refinance a portion of our bank
facility with proceeds from future bond and equity financings.

  We intend to create and establish a midstream crude oil presence in Canada
that is similar to our existing operations in the U.S. By using the knowledge
and skills developed in our U.S. operations, we hope to generate attractive
financial returns in the Canadian market through exploiting existing
inefficiencies, while attempting to improve revenues and margins on our acquired
pipeline, terminalling and gathering assets. These assets complement our current
activities and enhance our ability to service the needs of refiners in the U.S.
Midwest. The completion of both transactions, while independent of one another,
will provide us with direct access to substantial Canadian wellhead volumes via
gathering and pipeline systems and strategically located terminal and storage
assets.

 Scurlock Acquisition

  On May 12, 1999, we completed the acquisition of Scurlock Permian LLC 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 and the sale of 1.3 million Class
B Units to our general partner for total cash consideration of $25.0 million.

                                       7

  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 is an 800-mile
pipeline and gathering system located in the Spraberry Trend in West Texas than
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.

 West Texas Gathering System Acquisition

  On July 15, 1999, we completed the acquisition of the West Texas Gathering
System from Chevron Pipe Line Company for approximately $36.0 million, including
transaction costs. Financing for the amounts paid at closing was provided by a
draw under a previous credit facility. The assets acquired include approximately
450 miles of crude oil transmission mainlines, approximately 400 miles of
associated gathering and lateral lines, and approximately 2.9 million barrels of
tankage located along the system.

 All American Pipeline Linefill Sale and Asset Disposition

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

  We had suspended shipments of crude oil on this segment of the pipeline in
November 1999. At that time, we owned approximately 5.2 million barrels of crude
oil in the segment of the pipeline. We sold this crude oil from November 1999 to
February 2000 for net proceeds of approximately $100.0 million, which were used
for working capital purposes. We recognized gains of approximately $28.1 million
and $16.5 million in 2000 and 1999, respectively, in connection with the sale of
the linefill.

CRUDE OIL PIPELINE OPERATIONS

  We present below a description of our principal pipeline assets. All of our
pipeline systems are operated from one of two central control rooms with
computer systems designed to continuously monitor real time operational data
including measurement of crude oil quantities injected in and delivered through
the pipelines, product flow rates and pressure and temperature variations. This
monitoring and measurement technology provides us the ability to efficiently
batch differing crude oil types with varying characteristics through the
pipeline systems. The systems are designed to enhance leak detection
capabilities, sound automatic alarms in the event of operational conditions
outside of pre-established parameters and provide for remote-controlled shut-
down of pump stations on the pipeline systems. Pump stations, storage facilities
and meter measurement points along the pipeline systems are linked by telephone,
microwave, satellite or radio communication systems for remote monitoring and
control, which reduces our requirement for full time site personnel at most of
these locations.

  We perform scheduled maintenance on all of our pipeline systems and make
repairs and replacements when necessary or appropriate. We attempt to control
corrosion of the mainlines through the use of corrosion inhibiting chemicals
injected into the crude stream, external coatings and anode bed based or
impressed current cathodic protection systems. Maintenance facilities containing
equipment for pipe repairs, spare parts and trained response personnel are
strategically located along the pipelines and in concentrated operating areas.
We believe that all of our pipelines have been constructed and are maintained in
all material respects in accordance with applicable federal, state and local
laws and regulations, standards prescribed by the American Petroleum Institute
and accepted industry practice.

 All American Pipeline

  The segment of the All American Pipeline that we retained following the sale
of the line to El Paso is a common carrier crude oil pipeline system that
transports crude oil produced from Outer Continental Shelf ("OCS") fields
offshore California to locations in California. See " - All American Pipeline
Linefill Sale and Asset Disposition." This segment is subject to tariff rates
regulated by the Federal Energy Regulatory Commission ("FERC") (see " -
Regulation - Transportation Regulation"). As a common carrier, the All American
Pipeline offers transportation services to any shipper of crude oil, provided
that the crude oil tendered for transportation satisfies the conditions and
specifications contained in the applicable tariff. As a result, we transport
both our own crude oil and crude oil owned by third parties on the All American
Pipeline.

                                       8

  We currently operate the segment of the system that extends approximately 10
miles from ExxonMobil's onshore facilities at Las Flores on the California coast
to Plains Resources' onshore facilities at Gaviota, California (24-inch diameter
pipe) and continues from Gaviota approximately 130 miles to our station in
Emidio, California (30-inch pipe). Between Gaviota and our Emidio Station, the
All American Pipeline interconnects with our SJV Gathering System as well as
various third party intrastate pipelines, including the Unocap Pipeline System,
Pacific Pipeline, and a pipeline owned by EOTT Energy Partners, L.P.

  System Supply. The All American Pipeline currently transports OCS crude oil
received at the onshore facilities of the Santa Ynez field at Las Flores,
California and the onshore facilities of the Point Arguello field located at
Gaviota, California.

  ExxonMobil, which owns all of the Santa Ynez production, and Plains Resources,
Texaco and Sun Operating L.P., which together own approximately one-half of the
Point Arguello production, have entered into transportation agreements
committing to transport all of their production from these fields on our
retained segment of the All American Pipeline. These agreements, which expire in
August 2007, provide for a minimum tariff with annual escalations. At December
31, 2000, the tariffs averaged $1.41 per barrel for deliveries to connecting
pipelines in California. The tariff was increased by 10% effective January 1,
2001. The agreements do not require these owners to transport a minimum volume.
The producers from the Point Arguello field who do not have contracts with us
have no other means of transporting their production and, therefore, ship their
volumes on the All American Pipeline at the posted tariffs. For the year ended
December 31, 2000, approximately $24.6 million, or 18% of our gross margin was
attributable to the Santa Ynez field and approximately $7.8 million, or 6%, was
attributable to the Point Arguello field. Transportation of volumes commenced
from the Point Arguello field on the All American Pipeline in 1991 and from the
Santa Ynez field in 1994.

  The table below sets forth the historical volumes received from both of these
fields.

                                                                             YEAR ENDED DECEMBER 31,
                                             -----------------------------------------------------------------------------------
                                             2000     1999     1998      1997      1996      1995      1994      1993      1992
                                             ----     ----     ----      ----      ----      ----      ----      ----      -----
                                                                              (BARRELS IN THOUSANDS)
                                                                                                  
  Average daily volumes received from:
    Point Arguello (at Gaviota)               18        20        26        30        41        60        73        63        47
    Santa Ynez (at Las Flores)                56        59        68        85        95        92        34         -         -
                                              --        --        --       ---       ---       ---       ----       ---       --
         Total                                74        79        94       115       136       152       107        63        47
                                              ==        ==        ==       ===       ===       ===       ===        ==        ==

  A wholly owned subsidiary of Plains Resources is the operator of record for
the Point Arguello Unit. All of the volumes attributable to Plains Resources'
interests are committed for transportation on the All American Pipeline and are
subject to our Marketing Agreement with Plains Resources. Plains Resources
expects that there will continue to be natural production declines from each of
these fields as the underlying reservoirs are depleted. As operator of Point
Arguello, Plains Resources is conducting additional drilling and other
activities on this field, but we cannot assure you that these activities will
affect the production decline.

  San Joaquin Valley Supply. The San Joaquin Valley is one of the most prolific
oil producing regions in the continental United States, producing approximately
568,000 barrels per day of crude oil during the first nine months of 2000 which
accounted for approximately 68% of total California production and 12% of the
total production in the lower 48 states.

  The following table reflects the historical production for the San Joaquin
Valley as well as total California production (excluding OCS volumes) as
reported by the California Division of Oil and Gas.

                                                                             YEAR ENDED DECEMBER 31,
                                       -------------------------------------------------------------------------------------------
                                       2000 (1) 1999     1998      1997      1996      1995      1994      1993      1992     1991
                                       -------- ----     ----      ----      ----      ----      ----      ----      -----    ----
                                                                        (BARRELS IN THOUSANDS)
                                                                                                 
  Average daily volumes:
    San Joaquin Valley production (2)   568      562      592       584       579       569       578       588       609      634
    Total California production
        (excluding OCS volumes)         739      734      781       781       772       764       784       803       835      875

- -----------------------------
(1)  Reflects information through September 2000.
(2)  Consists of production from California Division of Oil and Gas District IV.

                                       9

  System Demand. Deliveries from the All American Pipeline are made to
California refineries through connections with third-party pipelines at Sisquoc,
Pentland and Emidio. Deliveries at Mojave were discontinued in the second
quarter of 1999, and volumes previously delivered to Mojave are delivered to
Emidio.

  The following table sets forth All American Pipeline average deliveries per
day within California.

                                                      YEAR ENDED DECEMBER 31,
                                          -------------------------------------------------
                                            2000       1999        1998     1997      1996
                                          -------     ------      ------   ------    -------
                                                       (BARRELS IN THOUSANDS)
                                                                        
    Average daily volumes delivered to:
        Sisquoc                               25         27         24        21       17
        Pentland                              49         52         69        74       71
        Mojave                                 -          7         22        32        6
        Emidio                                41         15          -         -        -
                                             ---        ---        ---       ---       --
           Total                             115        101        115       127       94
                                             ===        ===        ===       ===       ==

 SJV Gathering System

  The SJV Gathering System is a proprietary pipeline system. As a proprietary
pipeline, the SJV Gathering System is not subject to common carrier regulations.

  The SJV Gathering System was constructed in 1987 with a design capacity of
approximately 140,000 barrels per day. The system consists of a 16-inch pipeline
that originates at the Belridge station and extends 45 miles south to a
connection with the All American Pipeline at the Pentland station. The SJV
Gathering System is connected to several fields, including the South Belridge,
Elk Hills and Midway Sunset fields, three of the seven largest producing fields
in the lower 48 states. In 1999, we leased a pipeline that provides us access to
the Lost Hills field. The SJV Gathering System also includes approximately
586,000 barrels of tank capacity, which can be used to facilitate movements
along the system as well as to support our other activities.

  The SJV Gathering System is supplied with crude oil production primarily from
major oil companies' equity production from the South Belridge, Cymeric, Midway
Sunset, Elk Hills and Lost Hills fields. The table below sets forth the
historical volumes received into the SJV Gathering System.

                                                             YEAR ENDED DECEMBER 31,
                                       ------------------------------------------------------------
                                       2000         1999          1998          1997          1996
                                       ----         ----          -----         ----          -----
                                                        (BARRELS IN THOUSANDS)
                                                                                
    Total average daily volumes         60            84            85            91            67

 West Texas Gathering System

  We purchased the West Texas Gathering System from Chevron Pipe Line Company in
July 1999 for approximately $36.0 million, including transaction costs. The West
Texas Gathering System is a common carrier crude oil pipeline system located in
the heart of the Permian Basin producing area. The West Texas Gathering System
has lease gathering facilities in Crane, Ector, Upton, Ward and Winkler
counties. In the aggregate, these counties have produced on average in excess of
150,000 barrels per day of crude oil over the last four years. The West Texas
Gathering System was originally built by Gulf Oil Corporation in the late
1920's, expanded during the late 1950's and updated during the mid 1990's. The
West Texas Gathering System provides us with considerable flexibility, as major
segments are bi-directional and allow us to move crude oil between three of the
major trading locations in West Texas. Total system volumes were approximately
75,000 barrels per day in 2000.

  Lease volumes gathered into the system average approximately 50,000 barrels
per day. 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 (currently representing approximately 20,000 barrels per day, or 40%
of total system gathering volumes and 27% of the total system volumes). Other
large producers connected to the gathering system include Burlington Resources,
Devon Energy, Anadarko, Altura, Bass, and TotalFinaElf. Volumes from connecting
carriers, including ExxonMobil, Phillips and Unocal, average approximately
47,000 barrels per day. Our West Texas Gathering System has the capability to
transport approximately 190,000 barrels per day. At the time of the acquistion,
truck injection stations were limited and provided less than 1,000 barrels per
day. We have installed 16 truck injection stations on the West Texas Gathering
System since the acquisition. Our trucks are used to pick up crude oil produced
in the areas adjacent to the West Texas Gathering System and

                                       10

deliver these volumes into the pipeline. These additional injection stations
have allowed us to reduce the distance of our truck hauls in this area, increase
the utilization of our pipeline assets and reduce our operating costs. Volumes
received from truck injection stations were increased to 16,000 barrels per day
by the fourth quarter of 2000. The West Texas Gathering System also includes
approximately 2.9 million barrels of tank capacity located along the pipeline
system.

 Spraberry Pipeline System

  The Spraberry Pipeline System, acquired in the Scurlock acquisition, is a
proprietary pipeline system that 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 800 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. The Spraberry Pipeline
System gathers approximately 39,000 barrels per day of crude oil. Large
suppliers to the Spraberry Pipeline System include Coast Energy and Pioneer
Natural Resources. The Spraberry Pipeline System also includes approximately
173,000 barrels of tank capacity located along the pipeline.

 Sabine Pass Pipeline System

  The Sabine Pass Pipeline System, acquired in the Scurlock acquisition, is a
common carrier crude oil pipeline system. The primary purpose of the Sabine Pass
Pipeline System is to gather crude oil from onshore facilities of offshore
production near Johnson's Bayou, Louisiana, and deliver it to tankage and barge
loading facilities in Sabine Pass, Texas. The Sabine Pass Pipeline System
consists of approximately 34 miles of pipe ranging from 4 to 6 inches in
diameter and has a throughput capacity of approximately 26,000 barrels of
Louisiana light sweet crude oil per day. For the year ended December 31, 2000,
the system transported approximately 16,000 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 which is located in East Louisiana and
West Mississippi. The Ferriday Pipeline System consists of approximately 600
miles of pipe ranging from 2 inches to 12 inches in diameter. The Ferriday
Pipeline System delivers 9,000 barrels per day of crude oil to third-party
pipelines that supply refiners in the Midwest. The Ferriday Pipeline System also
includes approximately 348,000 barrels of tank capacity located along the
pipeline.

  In November 1999, we completed the construction of an 8-inch pipeline
underneath the Mississippi River that connects our Ferriday Pipeline System in
West Mississippi with the portion of the system located in East Louisiana. This
connection provides us with bi-directional capability to access additional
markets and enhances our ability to service our pipeline customers and take
advantage of additional high margin merchant activities.

 East Texas Pipeline System

  The East Texas Pipeline System, acquired in the Scurlock acquisition, is a
proprietary crude oil pipeline system that is used to gather approximately
15,000 barrels per day of crude oil in East Texas and to transport approximately
24,000 barrels per day of crude oil to Crown Central's refinery in Longview,
Texas. The deliveries to Crown Central are subject to a throughput and
deficiency agreement, which extends through 2004. The East Texas Pipeline System
also includes approximately 221,000 barrels of tank capacity located along the
pipeline.

 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 170 miles of pipe of varying diameter and delivers approximately
10,000 barrels per day of crude oil to third-party pipelines that supply
refiners in the Midwest. Approximately 3,300 barrels per day of the supply on
this system are from fields operated by Plains Resources.

                                       11

TERMINALLING AND STORAGE ACTIVITIES AND GATHERING AND MARKETING ACTIVITIES

 Terminalling and Storage Activities

  We own approximately 9.8 million barrels of terminalling and storage assets,
including tankage associated with our pipeline and gathering systems. Our
storage and terminalling operations increase the margins in our business of
purchasing and selling crude oil and also generate revenue through a combination
of storage and throughput charges to third parties. Storage fees are generated
when we lease tank capacity to third parties. Terminalling fees, also referred
to as throughput fees, are generated when we receive crude oil from one
connecting pipeline and redeliver crude oil to another connecting carrier in
volumes that allow the refinery to receive its crude oil on a ratable basis
throughout a delivery period. Both terminalling and storage fees are generally
earned from:

  .  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 support our arbitrage activities positions us to
capture margins in a contango market (when the oil prices for future deliveries
are higher than current prices) or when the market switches from contango to
backwardation (when the oil prices for future deliveries are lower than current
prices).

  Our most significant terminalling and storage asset is our Cushing Terminal.
The terminal was constructed in 1993, and expanded by approximately 50% in 1999,
to capitalize on the crude oil supply and demand imbalance in the Midwest. The
imbalance was caused by the continued decline of regional production supplies,
increasing imports and an inadequate pipeline and terminal infrastructure. The
Cushing Terminal is also used to support and enhance the margins associated with
our merchant activities relating to our lease gathering and bulk trading
activities.

  The Cushing Terminal has total storage capacity of approximately 3.1 million
barrels. The Cushing Terminal is comprised of fourteen 100,000 barrel tanks,
four 150,000 barrel tanks and four 270,000 barrel tanks, which are used to store
and terminal crude oil. The Cushing Terminal also includes a pipeline manifold
and pumping system that has an estimated daily throughput capacity of
approximately 800,000 barrels per day. The pipeline manifold and pumping system
is designed to support more than ten million barrels of tank capacity. The
Cushing Terminal is connected to the major pipelines and terminals in the
Cushing Interchange through pipelines that range in size from 10 inches to 24
inches in diameter.

  The Cushing Terminal is a state-of-the-art facility 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 contamination and maintain
     crude integrity during changes of service;
  .  mixer(s) on each tank to facilitate blending crude 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 varieties of crude transported through the
Cushing Interchange.

  The Cushing Terminal also incorporates numerous environmental and operational
safeguards. We believe that our terminal is the only one at the Cushing
Interchange in which each tank has a secondary liner (the equivalent of double
bottoms), leak detection devices and secondary seals. The Cushing Terminal is
the only terminal at the Cushing Interchange equipped with aboveground
pipelines. Like the pipeline systems we operate, the Cushing Terminal is
operated by a computer system designed to monitor real time operational data and
each tank is cathodically protected. In addition, each tank is

                                       12

equipped with an audible and visual high level alarm system to prevent
overflows; a double seal floating roof that minimizes air emissions and prevents
the possible accumulation of potentially flammable gases between fluid levels
and the roof of the tank; and a foam dispersal system that, in the event of a
fire, is fed by a fully-automated fire water distribution network.

  The Cushing Interchange is the largest wet barrel trading hub 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.

  The following table sets forth throughput volumes for our terminalling and
storage operations, and quantity of tankage leased to third parties from 1996
through 2000.

                                                                                        YEAR ENDED DECEMBER 31,
                                                                  --------------------------------------------------------------
                                                                  2000           1999           1998          1997          1996
                                                                  ----           ----           ----          ----          ----
                                                                                         (BARRELS IN THOUSANDS)
                                                                                                             
Throughput volumes (average daily volumes):
  Cushing Terminal                                                  59             72             69            69            56
  Ingleside Terminal                                                 8             11             11             8             3
                                                                 -----          -----         ------           ---           ---
    Total                                                           67             83             80            77            59
                                                                 =====          =====         ======           ===           ===
Storage leased to third parties (average monthly volumes):
  Cushing Terminal                                               1,437          1,743            890           414           203
  Ingleside Terminal                                               220            232            260           254           211
                                                                 -----          -----         ------           ---           ---
    Total                                                        1,657          1,975          1,150           668           414
                                                                 =====          =====         ======           ===           ===

 Gathering and Marketing Activities

  Our gathering and marketing activities are conducted in 23 states; however,
the vast majority of those activities are in Texas, Louisiana, California,
Illinois and the Gulf of Mexico. 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 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. For the year ended December 31, 2000, we purchased approximately
262,000 barrels per day of crude oil directly at the wellhead from more than
3,100 producers from approximately 19,400 leases. We purchase crude oil from
producers under contracts that range in term from a thirty-day evergreen to
three years. Gathering and marketing activities are characterized by large
volumes of transactions with lower margins relative to pipeline and terminalling
and storage operations.

  In the period immediately following the disclosure of the unauthorized trading
losses in 1999, a significant number of our suppliers and trading partners
reduced or eliminated the open credit previously extended to us. Consequently,
the amount of letters of credit we needed to support the level of our crude oil
purchases then in effect increased significantly. In addition, the cost of
letters of credit increased under our credit facility. Some of our purchase
contracts were terminated. As a result of these changes, aggregate volumes
purchased have declined from an average of 528,000 barrels per day for the
fiscal quarter preceding the trading loss to an average of 302,000 barrels per
day in the fourth quarter of 2000. Approximately 72,000 barrels per day of the
decrease is related to barrels gathered at producer lease locations and 154,000
barrels per day is attributable to bulk purchases. See "Unauthorized Trading
Losses" and Item 7. - "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources".

                                       13

  The following table shows the average daily volume of our lease gathering and
bulk purchases from 1996 through 2000.

                                           YEAR ENDED DECEMBER 31,
                                   --------------------------------
                                   2000  1999 (1)  1998  1997  1996
                                   ----  -------   ----  ----  ----
                                        (BARRELS IN THOUSANDS)

       Lease gathering              262    265      88     71    59
       Bulk purchases                28    138      98     49    32
                                    ---    ---     ---    ---    --
         Total volumes              290    403     186    120    91
                                    ===    ===     ===    ===    ==
- ----------------
(1)  Includes volumes from Scurlock Permian since May 1, 1999.

  Crude Oil Purchases. In a typical producer's operation, crude oil flows from
the wellhead to a separator where the petroleum gases are removed. After
separation, the crude oil is treated to remove water, sand and other
contaminants and is then moved into the producer's on-site storage tanks. When
the tank is full, the producer contacts our field personnel to purchase and
transport the crude oil to market. We utilize our truck fleet and gathering
pipelines and third-party pipelines, trucks and barges to transport the crude
oil to market.

  We have a Marketing Agreement with Plains Resources Inc., under which we are
the exclusive marketer/purchaser for all of Plains Resources' equity crude oil
production. The Marketing Agreement provides that we will purchase for resale at
market prices all of Plains Resources' equity crude oil production 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. The Marketing Agreement will
terminate upon a "change of control" of Plains Resources or our general partner.

  Bulk Purchases. In addition to purchasing crude oil at the wellhead from
producers, we purchase crude oil in bulk at major pipeline terminal points. This
production 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. Our bulk purchasing
activities are concentrated in California, Texas, Louisiana and at the Cushing
Interchange.

  Crude Oil Sales. The marketing of crude oil is complex and requires detailed
current 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.

  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 with respect to
futures contracts on the NYMEX. 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 fixed price
delivery contracts, floating price collar arrangements, financial swaps and
crude oil futures contracts as hedging devices. Our policy is generally to
purchase only crude oil for which we have a market, and to structure our sales
contracts so that crude oil price fluctuations do not materially affect the
gross margin we receive. We do not acquire and hold crude oil, futures contracts
or other derivative products for the purpose of speculating on crude oil price
changes that might expose us to indeterminable losses. In November 1999, we
discovered that this policy was violated, and we incurred $174.0 million in
unauthorized trading losses, including estimated associated costs and legal
expenses. In 2000, we recognized an additional $7.0 million charge for
litigation related to the unauthorized trading losses. See "Unauthorized Trading
Losses".

  Risk management strategies, including those involving price hedges using NYMEX
futures contracts, have become increasingly important in creating and
maintaining margins. See Item 7. - "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Outlook". Such hedging
techniques require significant resources dedicated to managing futures
positions. We are able to monitor crude oil volumes, grades, locations and
delivery schedules and to coordinate marketing and exchange opportunities, as
well as NYMEX hedging positions. This coordination ensures that our NYMEX
hedging activities are successfully implemented. We have a Risk Manager that has
direct responsibility and authority for our risk policies and our trading
controls and procedures and other aspects of corporate risk management.

                                       14

  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 nearly 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 an earlier or 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
more than 3,100 producers. 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. High-quality
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.

  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. Such arrangements include open lines of credit directly with us and
standby letters of credit issued under our letter of credit facility.  In the
period immediately following the disclosure of the 1999 unauthorized trading
losses, the amount of letters of credit we needed to support the level of our
crude oil purchases then in effect increased significantly. Currently, our
letter of credit requirement levels are lower than those levels existing prior
to the unauthorized trading losses. See "Unauthorized Trading Losses".

  When we market crude oil, we must determine the amount, if any, of the line of
credit to be extended to any given customer. If we determine that a customer
should receive a credit line, we must then decide on the amount of credit that
should be extended. Since our typical sales transactions can involve tens of
thousands of barrels of crude oil, the risk of nonpayment and nonperformance by
customers is a major consideration in our business. We believe our sales are
made to creditworthy entities or entities with adequate credit support.

  Credit review and analysis are also integral to our leasehold purchases.
Payment for all or substantially all of the monthly leasehold production is
sometimes made to the operator of the lease. The operator, in turn, is
responsible for the correct payment and distribution of such production proceeds
to the proper parties. In these situations, we must determine whether the
operator has sufficient financial resources to make such payments and
distributions and to indemnify and defend us in the event any third party should
bring a protest, action or complaint in connection with the ultimate
distribution of production proceeds by the operator.

OPERATING ACTIVITIES

  See Note 17 in the Notes to the Consolidated and Combined Financial Statements
appearing elsewhere in this report for information with respect to our pipeline
activities and terminalling and storage and gathering and marketing activities
and also those of our predecessor.

                                       15

CUSTOMERS

  Customers accounting for more than 10% of sales for the periods indicated are
as follows:

                                                                                PERCENTAGE
                                          ----------------------------------------------------------------------------
                                                                                  NOVEMBER 23,            JANUARY 1,
                                                YEAR ENDED DECEMBER 31,              1998 TO                1998 TO
                                          --------------------------------        DECEMBER 31,           NOVEMBER 22,
CUSTOMER                                       2000                1999              1998                    1998
- ----------------------------------        ------------           ---------        ------------           ------------
                                                                                                 
Marathon Ashland Petroleum                    12%                     -                 -                      -
Sempra Energy Trading Corporation              -                     22%               20%                    31%
Koch Oil Company                               -                     19%                -                     19%
ExxonMobil                                     -                      -                11%                     -

  All of the customers above pertain to our marketing, gathering, terminalling
and storage segment.

COMPETITION

  Competition among pipelines is based primarily on transportation charges,
access to producing areas and demand for the crude oil by end users. We believe
that high capital requirements, environmental considerations and the difficulty
in acquiring rights of way and related permits make it unlikely that competing
pipeline systems comparable in size and scope to our pipeline systems will be
built in the foreseeable future.

  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 substantially greater supplies of crude oil.

REGULATION

  Our operations are subject to extensive regulations. Many federal, state and
local departments and agencies are authorized by statute to issue and have
issued laws and regulations binding on the oil industry and its individual
participants. The failure to comply with such rules and regulations can result
in substantial penalties. The regulatory burden on the oil industry increases
our cost of doing business and, consequently, affects our profitability.
However, we do not believe that we are affected in a significantly different
manner by these laws and regulations than are our competitors. Due to the myriad
of complex federal, state and local regulations that may affect us, directly or
indirectly, you should not rely on the following discussion of certain laws and
regulations as an exhaustive review of all regulatory considerations affecting
our operations.

 Pipeline Regulation

  Our petroleum pipelines are subject to regulation by the U.S. Department of
Transportation with respect to the design, installation, testing, construction,
operation, replacement, and management of pipeline facilities. In addition, we
must permit access to and copying of records, and must make certain reports and
provide information as required by the Secretary of Transportation. Comparable
regulation exists in some states in which we conduct intrastate common carrier
or private pipeline operations. We believe that our pipeline operations are in
substantial compliance with applicable requirements.

  Pipeline safety issues are currently receiving significant attention in
various political and administrative arenas at both the state and federal
levels.  For example, a pipeline safety bill passed the Senate late last year
but was defeated in the House. In the current Congress, the Senate has approved
a similar bill unanimously. These developments renew the prospect of incurring
significant expenses if additional safety requirements are imposed that exceed
our current pipeline control system capabilities.

  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.

                                       16

 Transportation Regulation

  General Interstate Regulation.  Our interstate common carrier pipeline
operations are subject to rate regulation by the Federal Energy Regulatory
Commission ("FERC") under the Interstate Commerce Act. The Interstate Commerce
Act requires that tariff rates for petroleum pipelines, which includes crude
oil, as well as refined product and petrochemical pipelines, be just and
reasonable and non-discriminatory.  The Interstate Commerce Act permits
challenges to proposed new or changed rates by protest, and challenges to rates
that are already final and in effect by complaint.  Upon the appropriate
showing, a successful complainant may obtain reparations for overcharges
sustained for a period of up to two years prior to the filing of a complaint.

  The FERC is authorized to suspend the effectiveness of a new or changed tariff
rate for a period of up to seven months and to investigate the rate.  If upon
the completion of an investigation the FERC finds that the rate is unlawful, it
will order the pipeline to change its rates prospectively to the lawful level
and may require the pipeline to refund to shippers, with interest, any
difference between the rates the FERC determines to be lawful and the rates
under investigation.

  In general, petroleum pipeline rates must be cost-based, although settlement
rates, which are rates that have been agreed to by all shippers, are permitted,
and market-based rates may be permitted in certain circumstances.  Cost-based
rates are just and reasonable if they generate operating revenues, on the basis
of projected volumes, not greater than the total of operating expenses,
depreciation and amortization, federal and state income taxes and an allowed
rate of return on the pipeline's "rate base."

  Energy Policy Act of 1992 and Subsequent Developments.  In October 1992,
Congress passed the Energy Policy Act of 1992, 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. Rate increases
made pursuant to the indexing methodology are subject to protest, but such
protests must show that the portion of the rate increase resulting from
application of the index is substantially in excess of the pipeline's increase
in costs.  If the indexing methodology results in a reduced ceiling level that
is lower than a pipeline's filed rate, Order No. 561 requires the pipeline to
reduce its rate to comply with the lower ceiling. A pipeline must, as a general
rule, utilize the indexing methodology to change its rates. The FERC, however,
retained cost-of-service ratemaking, market-based rates, and settlement as
alternatives to the indexing approach, which alternatives may be used in certain
specified circumstances.

  The Act deemed petroleum pipeline rates in effect for the 365-day period
ending on the date of enactment of the Energy Policy Act or that were in effect
on the 365th day preceding enactment and had not been subject to complaint,
protest or investigation during the 365-day period to be just and reasonable
under the Interstate Commerce Act.  Generally, complaints against such
"grandfathered" rates may only be pursued if the complainant can show that a
substantial change has occurred since enactment in either the economic
circumstances or the nature of the services which were a basis for the rate or
that a provision of the tariff is unduly discriminatory or preferential.

  In a proceeding involving Lakehead Pipe Line Company, Limited Partnership
(Opinion No. 397), FERC concluded that there should not be a corporate income
tax allowance built into a petroleum pipeline's rates to reflect income
attributable to noncorporate partners since noncorporate partners, unlike
corporate partners, do not pay a corporate income tax.  On January 13, 1999, the
FERC issued Opinion No. 435 in a Santa Fe Proceeding, which, among other things,
affirmed Opinion No. 397's determination that there should not be a corporate
income tax allowance built into a petroleum pipeline's rates to reflect income
attributable to noncorporate partners. On rehearing, the FERC affirmed its
position; however, additional rehearing requests on other matters remain
pending. Petitions for review of Opinion No. 435 are before the D.C. Circuit
Court of Appeals, but are being held in abeyance pending FERC action on the
remaining rehearing requests. Once the rehearing process is completed, the
FERC's position on the income tax allowance and on other rate issues could be
subject to judicial review.

  Our Pipelines. The FERC generally has not investigated rates, such as those
currently charged by us, which have been mutually agreed to by the pipeline and
the shippers or which are significantly below cost of service rates that might
otherwise be justified by the pipeline under the FERC's cost-based ratemaking
methods. Substantially all of our gross margins on transportation are produced
by rates that are either grandfathered or set by agreement of the parties. The
indexing method has not required a reduction in these rates. Rates for OCS crude
are set by transportation agreements with shippers that do not expire until 2007
and provide for a minimum tariff with annual escalation. The FERC has twice
approved the agreed OCS rates, although application of the indexing method would
have required their reduction. When these OCS agreements expire in 2007, they
will be subject to renegotiation or to any of the other methods for establishing
rates under Order No. 561.  As a

                                       17

result, we believe that the rates now in effect can be sustained, although no
assurance can be given that the rates currently charged would ultimately be
upheld if challenged. In addition, we do not believe that an adverse
determination on the tax allowance issue in the Santa Fe Proceeding would have a
detrimental impact upon our current rates.

 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. The trucking regulations cover, among other things, driver
operations, keeping of log books, truck manifest preparations, the placement of
safety placards on the trucks and trailer vehicles, drug and alcohol testing,
safety of operation and equipment, and many other aspects of truck operations.
We are also subject to the Occupational Safety and Health Act, as amended
("OSHA"), with respect to our trucking operations.

ENVIRONMENTAL REGULATION

 General

  Numerous federal, state 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. As with the industry generally, compliance with existing and
anticipated 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 that 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 these environmental laws and regulations and any
associated permits can result in the imposition of significant administrative,
civil and criminal penalties, injunctions and construction bans or delays. A
discharge of hydrocarbons or hazardous substances 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
claims made by neighboring landowners and other third parties for personal
injury and property damage.

 Water

  The Oil Pollution Act, as amended ("OPA"), was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972, as amended
("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 for onshore facilities of $350.0 million;
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. If a party fails 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.

  The FWPCA imposes restrictions and strict controls regarding the discharge of
pollutants into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters. The FWPCA imposes substantial
potential liability for the costs of removal, remediation and damages. We
believe that compliance with existing permits and compliance with foreseeable
new permit requirements will not have a material adverse effect on our financial
condition or results of operations.

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

                                       18

 Air Emissions

  Our operations are subject to the federal Clean Air Act, as amended, and
comparable state and local statutes. We believe that our operations are in
substantial compliance with these statutes in all states in which we operate.

  Amendments to the federal Clean Air Act enacted in late 1990 (the "1990
Federal Clean Air Act Amendments") 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. In addition, the 1990 Federal
Clean Air Act Amendments include a new operating permit for major sources
("Title V permits"), which applies to some of our facilities. Although we can
give no assurances, we believe implementation of the 1990 Federal Clean Air Act
Amendments will not have a material adverse effect on our financial condition or
results of operations.

 Solid Waste

  We generate wastes, including hazardous wastes, that are subject to the
requirements of the federal Resource Conservation and Recovery Act ("RCRA"), and
comparable state statutes. The EPA is considering the adoption of stricter
disposal standards for non-hazardous wastes, including oil and gas wastes. We
are not currently required to comply with a substantial portion of the RCRA
requirements because our operations generate minimal quantities of hazardous
wastes. However, it is possible that additional wastes, which could include
wastes currently generated as non-hazardous wastes during operations, will in
the future be designated as "hazardous wastes." Hazardous wastes are subject to
more rigorous and costly disposal requirements than are non-hazardous wastes.
Such changes in the regulations could result in additional capital expenditures
or operating expenses for us as well as the industry in general.

 Hazardous Substances

  The Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), also known as "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" into the environment. These persons include the owner or operator of
the site or sites where the release occurred and companies that disposed or
arranged for the disposal of the hazardous substances found at the site. Under
CERCLA, such persons may be subject to 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 from the responsible classes of persons the costs they
incur. It is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by
hazardous substances or other pollutants released into the environment. In the
course of our ordinary operations, we may generate waste that falls within
CERCLA's definition of a "hazardous substance." We may be 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,
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.

 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
keeping requirements and monitoring of occupational exposure to regulated
substances.

                                       19

 Endangered Species Act

  The Endangered Species Act, as amended ("ESA"), restricts activities that may
affect endangered species or their habitats. While certain of our facilities are
in areas that may be designated as habitat for endangered species, we believe
that we are in substantial compliance with the ESA. However, the discovery of
previously unidentified endangered species could cause us to incur additional
costs or operation restrictions or bans in the affected area.

 Hazardous Materials Transportation Requirements

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

ENVIRONMENTAL REMEDIATION

  In connection with our acquisition of Scurlock Permian, we identified a number
of areas of potential environmental exposure. Under the terms of our acquisition
agreement, Marathon Ashland is fully indemnifying us for areas of environmental
exposure which were identified at the time of the acquisition, including any and
all liabilities associated with two superfund sites at which it is alleged
Scurlock Permian deposited waste oils as well as any potential liability for
hydrocarbon soil and water contamination at a number of Scurlock Permian
facilities. For environmental liabilities which were not identified at the time
of the acquisition but which occurred prior to the closing, we have agreed to
pay the costs relating to matters that are under $25,000. Our liabilities
relating to matters discovered prior to May 2003 and that exceed $25,000, is
limited to an aggregate of $1.0 million, with Marathon Ashland indemnifying us
for any excess amounts. Marathon Ashland's indemnification obligations for
identified sites extend indefinitely while its obligations for non-identified
sites extend to matters discovered within four years of the date of acquisition
(May 12, 1999) of Scurlock Permian. While we do not believe that our liability,
if any, for environmental contamination associated with our Scurlock Permian
assets will be material, there can be no assurance in that regard. In any event,
should we be found liable, we believe that our indemnification from Marathon
Ashland should prevent such liability from having a material adverse effect on
our financial condition, results of operations or cash flows.

  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 which are discovered prior to July
2002 which exceed this $1.0 million threshold. During our pre-acquisition
investigation, we identified a number of sites along our West Texas Gathering
System on which there are hydrocarbon contaminated soils. While the total cost
of remediation of these sites has not yet been determined, we believe our
indemnification arrangement with Chevron Pipe Line Company should prevent such
costs from having a material adverse effect on our financial condition, results
of operations or cash flows.

  From 1994 to 1997, our Venice, Louisiana terminal experienced several releases
of crude oil and jet fuel into the soil. The Louisiana Department of
Environmental Quality has been notified of the releases. Marathon Ashland has
performed some soil remediation related to the releases. The extent of the
contamination at the sites is uncertain and there is a potential for groundwater
contamination. We do not expect expenditures related to this terminal to be
material, although we can provide no assurances in that regard.

  During 1997, the All American Pipeline experienced a leak in a segment of its
pipeline in California which resulted in an estimated 12,000 barrels of crude
oil being released into the soil. Immediate action was taken to repair the
pipeline leak, contain the spill and to recover the released crude oil. We have
expended approximately $400,000 to date in connection with this spill and do not
expect any additional expenditures to be material, although we can provide no
assurances in that regard.

  Prior to being acquired by our predecessor in 1996, the Ingleside Terminal
experienced releases of refined petroleum products into the soil and groundwater
underlying the site due to activities on the property. We are undertaking a
voluntary state-administered remediation of the contamination on the property to
determine the extent of the contamination. We have spent approximately $140,000
to date in investigating the contamination at this site. We do not anticipate
the total additional costs related to this site to exceed $250,000, although no
assurance can be given that the actual cost could not exceed such estimate. In
addition, a portion of any such costs may be reimbursed to us from Plains
Resources.

                                       20

  We may experience future releases of crude oil into the environment from our
pipeline and storage operations, or discover releases that were previously
unidentified. While 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.

OPERATIONAL HAZARDS AND INSURANCE

  A pipeline 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
damages and suspension of operations. We maintain insurance of various types
that we consider to be adequate to cover our operations and properties. The
insurance covers all of 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, including the potential loss of significant revenues.
Consistent with insurance coverage generally available to the industry, our
insurance policies provide limited coverage for losses or liabilities relating
to pollution, with broader coverage for sudden and accidental occurrences.

  The occurrence of a significant event not fully insured or indemnified
against, or the failure of a party to meet its indemnification obligations,
could materially and adversely affect our operations and financial condition. We
believe that we are adequately insured for public liability and property damage
to others with respect to our operations. With respect to all of our coverage,
no assurance can be given that we will be able to maintain adequate insurance in
the future at rates we consider reasonable.

TITLE TO PROPERTIES

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

  Some of the leases, easements, rights-of-way, permits and licenses transferred
to us, upon our formation in 1998 and in connection with acquisitions we have
made since that time, required the consent of the grantor to transfer such
rights, which in certain instances is a governmental entity. Our general partner
believes that it has 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, our general partner believes 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.

  Our general partner believes that we have satisfactory title to all of our
assets. Although title to such properties are subject to encumbrances in certain
cases, such as customary interests generally retained in connection with
acquisition of real property, liens related to environmental liabilities
associated with historical operations, liens for current taxes and other burdens
and minor easements, restrictions and other encumbrances to which the underlying
properties were subject at the time of acquisition by our predecessor or us, our
general partner believes that none of such 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.

EMPLOYEES

  To carry out our operations, our general partner or its affiliates employed
approximately 915 employees at December 31, 2000. None of the employees of our
general partner were represented by labor unions, and our general partner
considers its employee relations to be good.

                                       21

ITEM 3.  LEGAL PROCEEDINGS

  Texas Securities Litigation. On November 29, 1999, a class action lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit
alleged that Plains All American and certain of our general partner's officers
and directors violated federal securities laws, primarily in connection with
unauthorized trading by a former employee. An additional nineteen cases have
been filed in the Southern District of Texas, some of which name our general
partner and Plains Resources as additional defendants. All of the federal
securities claims are being consolidated into two actions. The first
consolidated action is that filed by purchasers of Plains Resources' common
stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al.
The second consolidated action is that filed by purchasers of our common units,
and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al.
Plaintiffs alleged that the defendants were liable for securities fraud
violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of
1934 and for  making false registration statements under Sections 11 and 15 of
the Securities Act of 1933.

  We and Plains Resources reached an agreement with representatives for the
plaintiffs for the settlement of all of the class actions, and in January 2001,
we deposited approximately $30.0 million under the terms of the settlement
agreement. The total cost of the settlement to us and Plains Resources,
including interest and expenses and after insurance reimbursements, was $14.9
million. Of that amount, $1.0 million was allocated to Plains Resources by
agreement between special independent committees of the board of directors of
our general partner and the board of directors of Plains Resources. All such
amounts were reflected in our financial statements at December 31, 2000. The
settlement is subject to a number of conditions, including final approval by the
court. A hearing is set for March 30, 2001. The settlement agreement does not
affect the Texas Derivative Litigation and Delaware Derivative Litigation
described below.

  Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits
were filed in the Delaware Chancery Court, New Castle County, entitled Susser v.
Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et
al. These suits, and three others which were filed in Delaware subsequently,
named our general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to Plains All American Pipeline, L.P. and its unitholders by failing
to monitor properly the activities of its employees. The court has consolidated
all of the cases under the caption In Re Plains All American Inc. Shareholders
Litigation, and has designated the complaint filed in Susser v. Plains All
American Inc. as the complaint in the consolidated action. A motion to dismiss
was filed on behalf of the defendants on August 11, 2000.

  The plaintiffs in the Delaware derivative litigation seek that the defendants

  . account for all losses and damages allegedly sustained by Plains All
    American from the unauthorized trading losses;
  . establish and maintain effective internal controls ensuring that our
    affiliates and persons responsible for our affairs do not engage in wrongful
    practices detrimental to Plains All American;
  . pay for the plaintiffs' costs and expenses in the litigation, including
    reasonable attorneys' fees, accountants' fees and experts' fees; and
  . provide the plaintiffs any additional relief as may be just and proper under
    the circumstances.

  We have reached an agreement in principle with the plaintiffs, subject to
approval by the Delaware court, to settle the Delaware litigation for
approximately $1.1 million.

  Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed
in the United States District Court of the Southern District of Texas entitled
Fernandes v. Plains All American Inc., et al, naming our general partner, its
directors and certain of its officers as defendants. This lawsuit contains the
same claims and seeks the same relief as the Delaware derivative litigation,
described above. A motion to dismiss was filed on behalf of the defendants on
August 14, 2000.

  We intend to vigorously defend the claims made in the Texas derivative
litigation. We believe that Delaware court approval of the settlement of the
Delaware derivative litigation will effectively preclude prosecution of the
Texas derivative litigation. However, there can be no assurance that we will be
successful in our defense or that this lawsuit will not have a material adverse
effect on our financial position or results of operation.

  We, in the ordinary course of business, are a claimant and/or a defendant in
various other legal proceedings. Management does 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.

                                       22

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

  No matters were submitted to a vote of the security holders, through
solicitation of proxies or otherwise, during the fourth quarter of the fiscal
year covered by this report.

                                    PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS

  The common units, excluding the Class B common units, are listed and traded on
the New York Stock Exchange under the symbol "PAA". On March 22, 2001, the
market price for the common units was $22 4/5 per unit and there were
approximately 14,378 recordholders and beneficial owners (held in street name).

  The following table sets forth high and low sales prices for the common units
as reported on the New York Stock Exchange Composite Tape, and the cash
distributions paid per common unit for the periods indicated:

                                     COMMON UNIT PRICE RANGE
                           -----------------------------------------------             CASH
                                 HIGH                   LOW                     DISTRIBUTIONS
                           ---------------------      --------------------     -------------------
                                                                            
2000:
1st Quarter                       $16   9/16             $13                        $0.450
2nd Quarter                        18    5/8              15   1/4                   0.463
3rd Quarter                        19    3/4              18                         0.463
4th Quarter                        20   1/16              18                         0.463

1999:
1st Quarter                       $19                    $15   7/8                  $0.450
2nd Quarter                        19  15/16              16  5/16                   0.463
3rd Quarter                        20                     17   3/8                   0.481
4th Quarter                        20    1/4               9   5/8                   0.450 (1)

- --------------------
(1)  A distribution was not made on the subordinated units for the fourth
     quarter of 1999.

  The Class B common units are pari passu with common units with respect to
quarterly distributions, 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.

  We have also issued subordinated units, all of which are held by an affiliate
of our general partner, for which there is no established public trading market.
We will distribute to our partners (including holders of subordinated units), on
a quarterly basis, all of our available cash in the manner described herein.
Available cash generally means, for any of our fiscal quarters, all cash on hand
at the end of the quarter less the amount of cash reserves that is necessary or
appropriate in the reasonable discretion of our 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.

  Minimum quarterly distributions are $0.45 for each full fiscal quarter.
Distributions of available cash to the holders of subordinated units are subject
to the prior rights of the holders of common units to receive the minimum
quarterly distributions for each quarter during the subordination period, and to
receive any arrearages in the distribution of minimum quarterly distributions on
the common units for prior quarters during the subordination period. The
expiration of the subordination period will generally not occur prior to
December 31, 2003.

  Under the terms of our bank credit agreement and letter of credit and
borrowing facility, 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 Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources".

                                       23

ITEM 6.  SELECTED FINANCIAL AND OPERATING DATA
     (in thousands, except unit and operating data)

  On November 23, 1998, we completed our initial public offering and the
transactions whereby we became the successor to the business of our predecessor.
The historical financial information below for Plains All American Pipeline was
derived from our audited consolidated financial statements as of December 31,
2000, 1999 and 1998, and for the years ended December 31, 2000 and 1999 and for
the period from November 23, 1998 through December 31, 1998. The financial
information below for our predecessor was derived from the audited combined
financial statements of our predecessor, as of December 31, 1997 and 1996 and
for the period from January 1, 1998 through November 22, 1998 and for the years
ended December 31, 1997 and 1996, including the notes thereto. The operating
data for all periods is derived from our records as well as those of our
predecessor. Commencing May 1, 1999, the results of operations of the Scurlock
Permian businesses are included in our results of operations. Commencing July
30, 1998, the results of operations of the All American Pipeline and the SJV
Gathering System are included in the results of operations of our predecessor
and Plains All American Pipeline. The selected financial data should be read in
conjunction with the consolidated and combined financial statements, including
the notes thereto, included elsewhere in this report, and Item 7, -"Management's
Discussion and Analysis of Financial Condition and Results of Operations".

                                                                                            PREDECESSOR
                                                                                -----------------------------------
                                                                   NOVEMBER 23,   JANUARY 1,          YEAR ENDED
                                        YEAR ENDED DECEMBER 31,     1998 TO       1998 TO           DECEMBER 31,
                                       ------------------------   DECEMBER 31,  NOVEMBER 22,    -------------------
                                         2000           1999         1998          1998          1997         1996
                                       ----------------------------------------------------------------------------
                                                                                         
Statement of Operations Data:
Revenues (1)                           $6,641,187    $10,910,423    $398,918   $3,118,353    $2,815,278   $1,996,715

Cost of sales
 and operations (1)                     6,506,504     10,800,109     391,419    3,087,372     2,802,798    1,987,184
Unauthorized trading losses and
 related expenses (2)                       6,963        166,440       2,400        4,700             -            -
                                       ----------    -----------    --------   ----------    ----------   ----------
Gross margin                              127,720        (56,126)      5,099       26,281        12,480        9,531
                                       ----------    -----------    --------   ----------    ----------   ----------
General and
 administrative expenses (3)               40,821         23,211         771        4,526         3,529        2,974
Depreciation and
 amortization                              24,523         17,344       1,192        4,179         1,165        1,140
Restructuring expense                           -          1,410           -            -             -            -
                                       ----------    -----------    --------   ----------    ----------   ----------
Total expenses                             65,344         41,965       1,963        8,705         4,694        4,114
                                       ----------    -----------    --------   ----------    ----------   ----------
Operating income (loss)                    62,376        (98,091)      3,136       17,576         7,786        5,417

Interest expense                          (28,691)       (21,139)     (1,371)     (11,260)       (4,516)      (3,559)
Gain on sale of assets (4)                 48,188         16,457           -            -             -            -
Interest and other income (5)              10,776            958          12          572           138           90
                                       ----------    -----------    --------   ----------    ----------   ----------
Net income (loss)
 before provision (benefit)
 in lieu of income taxes
 and extraordinary item                    92,649       (101,815)      1,777        6,888         3,408        1,948
Provision (benefit) in
 lieu of income taxes                           -              -           -        2,631         1,268          726
                                       ----------    -----------    --------   ----------    ----------   ----------
Net income (loss) before
 extraordinary item                    $   92,649    $  (101,815)   $  1,777   $    4,257    $    2,140   $    1,222
                                       ==========    ===========    ========   ==========    ==========   ==========
Basic and diluted
 net income (loss) per
 limited partner unit before
 extraordinary item (6)                $     2.64    $     (3.16)   $   0.06   $     0.25    $     0.12   $     0.07
                                       ==========    ===========    ========   ==========    ==========   ==========
Weighted average
 number of limited partner
 units outstanding                         34,386         31,633      30,089       17,004        17,004       17,004
                                       ==========    ===========    ========   ==========    ==========   ==========

                                                                     Table and footnotes continued on following page

                                       24

                                                                                            PREDECESSOR
                                                                                -----------------------------------
                                                                   NOVEMBER 23,   JANUARY 1,          YEAR ENDED
                                        YEAR ENDED DECEMBER 31,     1998 TO       1998 TO           DECEMBER 31,
                                       ------------------------   DECEMBER 31,  NOVEMBER 22,    -------------------
                                         2000           1999         1998 (1)      1998 (1)      1997         1996
                                       ----------------------------------------------------------------------------
                                                                                         
BALANCE SHEET DATA:
 (at end of period):
 Working capital (9)                     $ 47,111     $  101,539    $  2,231          N/A      $  2,017     $  2,586
 Total assets                             885,801      1,223,037     607,186          N/A       149,619      122,557
 Related party debt - Long-term                 -        114,000           -          N/A        28,531       31,811
 Total debt (10)                          321,300        368,819     184,750          N/A        18,000            -
 Partners' capital                        213,999        192,973     270,543          N/A             -            -
 Combined equity                                -              -           -          N/A         5,975        3,835

OTHER DATA:
 EBITDA (7)                             $ 103,048     $   89,074    $  6,740    $  27,027      $  9,089     $  6,647
 Maintenance capital
  expenditures (8)                          1,785          1,741         200        1,508           678        1,063
 Net cash provided by (used in)
  operating activities                    (33,511)       (71,245)      7,218       21,384       (12,869)         733
 Net cash provided by (used in)
  investing activities                    211,001       (186,093)     (3,089)    (399,611)       (1,854)      (3,285)
 Net cash provided by (used in)
  financing activities                   (227,832)       305,603       1,374      386,154        14,321        2,759

OPERATING DATA:
 Volumes (barrels per day):
  All American
   Tariff (11)                             73,800        102,700     110,200      113,700             -            -
   Margin (12)                             60,000         54,100      50,900       49,100             -            -
 Other                                    106,500         61,400           -            -             -            -
                                         --------     ----------    --------     --------      --------     --------
   Total pipeline                         240,300        218,200     161,100      162,800             -            -
                                         ========     ==========    ========     ========      ========     ========
 Lease gathering (13)                     262,600        264,700     126,200       87,100        71,400       58,500
 Bulk purchases (14)                       27,700        138,200     133,600       94,700        48,500       31,700
                                         ========     ==========    ========     ========      ========     ========
   Total                                  290,300        402,900     259,800      181,800       119,900       90,200
                                         ========     ==========    ========     ========      ========     ========
 Terminal throughput (15)                  67,000         83,300      61,900       81,400        76,700       59,800
                                         ========     ==========    ========     ========      ========     ========

- -----------------------
(1)  We have reclassified Revenues and Costs of Sales and Operations for periods
     prior to 2000 in accordance with Emerging Issues Task Force ("EITF") Issue
     No. 99-19 - "Recording Revenue Gross as a Principal versus Net as an
     Agent". See Item 7. - "Management's Discussion and Analysis of Financial
     Condition and Results of Operations - Recent Accounting Pronouncements".
     Reclassifications to Revenues and Cost of sales and operations for the
     years ended December 31, 2000 and 1999, for the periods November 23, 1988
     to December 31, 1998 and January 1, 1998 to November 22, 1998 and for the
     years ended December 31, 1997 and 1996 were $2.5 billion, $6.2 billion,
     $0.2 billion, $2.1 billion, $2.0 billion and $1.4 billion, respectively.
     This reclassification had no effect on earnings.
(2)  In November 1999, we discovered that a former employee had engaged in
     unauthorized trading activity, resulting in losses of approximately $162.0
     million ($174.0 million, including estimated associated costs and legal
     expenses of which $166.4 million and $7.1 million was recognized in 1999
     and 1998, respectively). In 2000, we recognized an additional $7.0 million
     charge for litigation related to the unauthorized trading losses. See Item
     1. - "Business - Unauthorized Trading Losses".
(3)  General and administrative expense for 2000 includes a $5.0 million charge
     to reserve potentially uncollectible accounts receivable. See Item 7. -
     "Management's Discussion and Analysis of Financial Condition and Results of
     Operations - Results of Operations".
(4)  In March 2000, we completed the sale of 5.2 million barrels of crude oil
     linefill from the All American Pipeline. We recognized gains of $28.1
     million and $16.5 million in 2000 and 1999, respectively, in connection
     with that sale. We also sold a segment of the All American Pipeline to El
     Paso and recognized a gain of $20.1 million in the first quarter of 2000.
     See Item 1. - "Acquisitions and Dispositions - All American Pipeline
     Linefill and Asset Disposition".
(5)  For the year ended December 31, 2000, this amount includes $9.7 million of
     previously deferred gains from terminated interest rate swaps recognized as
     a result of debt extinguishment.
(6)  Basic and diluted net income (loss) per unit is computed by dividing the
     limited partners' interest in net income by the number of outstanding
     common and subordinated units. For periods prior to November 23, 1998, the
     number of units are equal to the common and subordinated units received by
     our general partner in exchange for the assets contributed to the
     partnership.
(7)  EBITDA means earnings before interest expense, income taxes, depreciation
     and amortization. Adjusted EBITDA also excludes unauthorized trading
     losses, noncash compensation, restructuring expense, gains on the sale of
     linefill and pipeline, allowance for accounts receivable and extraordinary
     loss from extinguishment of debt. Adjusted EBITDA is not a measurement
     presented in accordance with GAAP and is not intended to be used in lieu of
     GAAP presentations of results of operations and cash provided by operating
     activities. EBITDA is commonly used by debt holders and financial statement
     users as a measurement to determine the ability of an entity to meet its
     interest obligations.

                                           Footnotes continued on following page

                                       25

(8)  Maintenance capital expenditures are capital expenditures made to replace
     partially or fully depreciated assets to maintain the existing operating
     capacity of existing assets or extend their useful lives. Capital
     expenditures made to expand our existing capacity, whether through
     construction or acquisition, are not considered maintenance capital
     expenditures. Repair and maintenance expenditures associated with existing
     assets that do not extend the useful life or expand operating capacity are
     charged to expense as incurred.
(9)  At December 31, 1999, working capital includes $37.9 million of pipeline
     linefill and $103.6 million for the segment of the All American Pipeline
     that were both sold in the first quarter of 2000. See Item 1. -
     "Acquisitions and Dispositions - All American Pipeline Linefill and Asset
     Disposition".
(10) Excludes related party debt.
(11) Represents crude oil deliveries on the All American Pipeline for the
     account of third parties.
(12) Represents crude oil deliveries on the All American Pipeline and the SJV
     Gathering System for the account of affiliated entities.
(13) Represents barrels of crude oil purchased at the wellhead, including
     volumes which were purchased under the Marketing Agreement.
(14) Represents barrels of crude oil purchased at collection points, terminals
     and pipelines.
(15) Represents total crude oil barrels delivered from the Cushing Terminal and
     the Ingleside Terminal.

                                       26

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS

  The following discussion of our financial condition and results of our
operations and those of the midstream subsidiaries of Plains Resources (our
"predecessor") should be read in conjunction with our historical consolidated
and combined financial statements and accompanying notes and those of our
predecessor included elsewhere in this report. For more detailed information
regarding the basis of presentation for the following financial information, see
the notes to the historical consolidated and combined financial statements.

OVERVIEW

  We were formed in September of 1998 to acquire and operate the midstream crude
oil business and assets of Plains Resources Inc. and its wholly owned
subsidiaries. On November 23, 1998, we completed our initial public offering and
the transactions whereby we became the successor to the business of our
predecessor. Our operations are conducted through Plains Marketing, L.P. and All
American Pipeline, L.P. Plains All American Inc., a wholly owned subsidiary of
Plains Resources, is our general partner. We are engaged in interstate and
intrastate marketing, transportation and terminalling of crude oil. 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."

  Pipeline Operations. Our activities from pipeline operations generally consist
of transporting third-party volumes of crude oil for a tariff and merchant
activities designed to capture price differentials between the cost to purchase
and transport crude oil to a sales point and the price received for such crude
oil at the sales point. Tariffs on our pipeline systems vary by receipt point
and delivery point. The gross margin generated by our tariff activities depends
on the volumes transported on the pipeline and the level of the tariff charged,
as well as the fixed and variable costs of operating the pipeline. Our ability
to generate a profit on margin activities is not tied to the absolute level of
crude oil prices but is generated by the difference between an index related
price paid and other costs incurred in the purchase of crude oil and an index
related price at which we sell crude oil. We are well positioned to take
advantage of these price differentials due to our ability to move purchased
volumes on our pipeline systems. We combine reporting of gross margin for tariff
activities and margin activities due to the sharing of fixed costs between the
two activities.

  Terminalling and Storage Activities and Gathering and Marketing Activities.
Gross margin from terminalling and storage activities is dependent on the
throughput volume of crude oil stored and the level of fees generated at our
terminalling and storage facilities. Gross margin from our gathering and
marketing activities is dependent on our ability to sell crude oil at a price in
excess of our aggregate cost. These 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 fluctuations in market related indices.

  During periods when the demand for crude oil is weak (as was the case in late
1997, 1998 and the first quarter of 1999), the market for crude oil is often in
contango, meaning that the price of crude oil for future deliveries is higher
than current prices. A contango market has a generally negative impact on
marketing margins, but is favorable to the storage business, because storage
owners at major trading locations (such as the Cushing Interchange) can
simultaneously purchase production at low 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 backward, meaning that the price of
crude oil for future deliveries is lower than current prices. A backward market
has a positive impact on marketing margins because crude oil gatherers can
capture a premium for prompt deliveries. 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.

  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 with respect to
futures contracts on the NYMEX. Through these transactions, we seek to maintain
a position that is substantially balanced between crude oil purchases and sales
and future delivery obligations. We purchase crude oil on both a fixed and
floating price basis. As fixed price barrels are purchased, we enter into sales
arrangements with refiners, trade partners or on the NYMEX, which establishes a
margin and protects it against future price fluctuations. When floating price
barrels are purchased, we match those contracts with similar type sales
agreements with our customers, or likewise establish a hedge position using the
NYMEX futures market. From time to time, we enter into arrangements that will
expose us to basis risk. Basis risk occurs when crude oil is purchased based on
a crude oil specification and location that differs from the countervailing
sales arrangement. Our policy is only to purchase crude oil for which we have a
market, and to structure our sales contracts so that crude oil price
fluctuations do not materially affect the gross margin which we receive. In
November 1999, we discovered that this policy was violated. See Item 1.
"Business - Unauthorized Trading Losses" and "Unauthorized Trading Losses"

                                       27

below. We do not acquire and hold crude oil futures contracts or other
derivative products for the purpose of speculating on crude oil price changes
that might expose us to indeterminable losses.

RECENT DEVELOPMENTS

  Consistent with our publicly announced intention to expand operations into
Canada, we are pursuing the acquisition of certain Canadian assets in two
separate transactions for aggregate consideration of approximately $200.0
million. See "Liquidity and Capital Resources - Recent Developments".

UNAUTHORIZED TRADING LOSSES

  In November 1999, we discovered that a former employee had engaged in
unauthorized trading activity, resulting in losses of approximately $174.0
million which includes estimated associated costs and legal expenses.
Approximately $7.1 million of the unauthorized trading losses was recognized in
1998 and the remainder in 1999. In 2000, we recognized an additional $7.0
million charge for litigation related to the unauthorized trading losses. See
Item 1. "Business - Unauthorized Trading Losses" for a discussion of the
unauthorized trading loss, its financial effects and the steps taken to prevent
future violations of our trading policies. See Item 3. - "Legal Proceedings".

RESULTS OF OPERATIONS

  In the fourth quarter of 2000, we adopted EITF 99-19. Prior to this adoption,
we reported the results of certain of our crude oil buy/sell and exchange
activities on a net margin basis. Under EITF 99-19, we report these activities
as gross revenues and costs of sales and operations. Revenues and costs of sales
and operations for all periods presented have been reclassified to reflect this
adoption, with no effect on earnings.

 Analysis of Three Years Ended December 31, 2000.

  The results of operations for the year ended December 31, 1999 include the
results of the Scurlock acquisition effective May 1, 1999 and the West Texas
Gathering System acquisition effective July 1, 1999. The combined results of
operations for the year ended December 31, 1998 are derived from our financial
statements for the period from November 23, 1998 through December 31, 1998, and
the combined financial statements of our predecessor for the period from January
1, 1998 through November 22, 1998, which in the following discussion are
combined and referred to as the year ended December 31, 1998. Commencing July
30, 1998 (the date of acquisition of the All American Pipeline and the SJV
Gathering System from Goodyear), the results of operations of the All American
Pipeline and the SJV Gathering System are included in the results of operations
of the predecessor.

  For 2000, we reported net income of $77.5 million on total revenue of $6.6
billion compared to a net loss for 1999 of $103.4 million on total revenue of
$10.9 billion and net income for 1998 of $6.0 million on total revenue of $3.5
billion. The results for the years ended December 31, 2000, 1999 and 1998
include the following items:

  2000
  .  a $28.1 million gain on the sale of crude oil linefill;
  .  a $20.1 million gain on the sale of the segment of the All American
     Pipeline that extends from Emidio, California, to McCamey, Texas;
  .  $9.7 million of previously deferred gains on interest rate swap
     terminations recognized due to the early extinguishment of debt;
  .  an extraordinary loss of $15.1 million related to the early extinguishment
     of debt;
  .  a $7.0 million charge for litigation related to the unauthorized trading
     losses;
  .  a $5.0 million reserve for potentially uncollectible accounts receivable;
  .  amortization of $4.6 million of debt issue costs associated with facilities
     put in place during the fourth quarter of 1999; and
  .  $3.1 million of noncash compensation expense.

                                       28

  1999
  .  $166.4 million of unauthorized trading losses;
  .  a $16.5 million gain on the sale of crude oil linefill that was sold in
     1999;
  .  restructuring expense of $1.4 million;
  .  an extraordinary loss of $1.5 million related to the early extinguishment
     of debt; and
  .  $1.0 million of noncash compensation expense.

  1998
  .  $7.1 million of unauthorized trading losses.

  Excluding the items listed above, we would have reported net income of $54.4
million, $50.6 million and $11.2 million for the years ended December 31, 2000,
1999 and 1998, respectively. Excluding the unauthorized trading losses, we
reported gross margin (revenues less direct expenses of purchases,
transportation, terminalling and storage and other operating and maintenance
expenses) of $134.7 million for the year ended December 31, 2000 compared to
$110.3 million and $38.5 million reported for 1999 and 1998, respectively. Gross
profit (gross margin less general and administrative expense), also excluding
the unauthorized trading losses, was $93.9 million, $87.1 million and $33.2
million for the years ended December 31, 2000, 1999 and 1998, respectively.

  The following table sets forth combined financial and operating information
for the periods presented and includes the impact of the items discussed above
(in thousands):

                                                     YEAR ENDED  DECEMBER 31,
                                             ------------------------------------------
                                               2000            1999             1998
                                               ----            ----             ----
                                                                        
Operating Results:
 Revenues                                    $6,641,187      $10,910,423      $3,517,271
                                             ==========      ===========      ==========
 Gross margin
  Pipeline                                   $   51,787      $    58,001      $   16,768
  Terminalling and storage
   and gathering and marketing                   82,896           52,313          21,712
  Unauthorized trading losses                    (6,963)        (166,440)         (7,100)
                                             ----------      -----------      ----------
    Total                                       127,720          (56,126)         31,380
 General and administrative expense             (40,821)         (23,211)         (5,297)
                                             ----------      -----------      ----------
 Gross profit                                $   86,899      $   (79,337)     $   26,083
                                             ==========      ===========      ==========
 Extraordinary item                          $  (15,147)     $    (1,545)     $        -
                                             ==========      ===========      ==========
 Net income (loss)                           $   77,502      $  (103,360)     $    6,034
                                             ==========      ===========      ==========
AVERAGE DAILY VOLUMES (BARRELS):
  Pipeline Activities:
    All American
      Tariff activities                              74              103             113
      Margin activities                              60               54              50
    Other                                           107               61               -
                                             ----------      -----------      ----------
    Total                                           241              218             163
                                             ==========      ===========      ==========
  Lease gathering                                   262              265              88
  Bulk purchases                                     28              138              98
                                             ----------      -----------      ----------
    Total                                           290              403             186
                                             ==========      ===========      ==========
  Terminal throughput                                67               83              80
                                             ==========      ===========      ==========
  Storage leased to third parties,
    monthly average volumes                       1,657            1,975           1,150
                                             ==========      ===========      ==========

  Revenues. Total revenues were $6.6 billion, $10.9 billion and $3.5 billion for
2000, 1999 and 1998, respectively. The decrease in 2000 as compared to 1999 was
primarily attributable to lower buy/sell and exchange volumes associated with
our gathering and marketing activities, partially offset by higher crude oil
prices. The increase in 1999 as compared to 1998 was primarily due to increased
volumes from our gathering and marketing activities, partially attributable to
the May 1999 Scurlock acquisition, as well as higher crude oil prices.

                                       29

  Cost of Sales and Operations. Cost of sales and operations increased to $6.5
billion from $10.8 billion and $3.5 billion in 1999 and 1998, respectively,
primarily due to the reasons discussed above for revenues.

  Unauthorized trading losses. As previously discussed, we recognized losses of
approximately $7.0 million, $166.4 million and $7.1 million in 2000, 1999 and
1998, respectively, as a result of unauthorized trading by a former employee.
See "Unauthorized Trading Losses."

  General and Administrative. General and administrative expenses were $40.8
million for the year ended December 31, 2000, compared to $23.2 million and $5.3
million for 1999 and 1998, respectively. The increase from 1999 to 2000 is
primarily due to (1) a $5.0 million reserve for potentially uncollectible
accounts receivable, (2) the Scurlock acquisition in mid-1999 ($5.7 million),
(3) consulting fees related to the unauthorized trading loss investigation, (4)
consulting and accounting charges related to system modifications and
enhancements and implementation of Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities"
("SFAS 133") and (5) noncash compensation expense. The increase from 1998 to
1999 was primarily attributable to the Scurlock and West Texas Gathering System
acquisitions in 1999 ($13.1 million), the All American Pipeline acquisition in
1998 ($0.7 million), expenses related to our operations as a public entity ($0.7
million) and continued expansion of our business activities.

  During 2000, a review of our accounts receivable indicated that certain
amounts would not be collectible within one year. Accordingly, we reclassified
approximately $10.0 million of accounts receivable from current assets to other
assets. In addition, we recorded a $5.0 million charge to reserve for
potentially uncollectible accounts receivable. During 2000 and 1999, we incurred
charges of $3.1 million and $1.0 million, respectively, related to noncash
incentive compensation paid to certain officers and key employees of Plains All
American Inc. and its affiliates. In 1998 and 2000, Plains All American Inc.
granted its employees the right to earn ownership in our common units owned by
Plains All American Inc. The units vest over a three-year period subject to
paying distributions on the common and subordinated units. See Item 11.-
"Executive Compensation - Transaction Grant Agreements," and Item 12. -
"Security Ownership of Certain Beneficial Owners and Management." These amounts
are included in general and administrative expense on the Consolidated
Statements of Operations.

  We expect general and administrative expenses to run approximately $8.5
million to $9.0 million per quarter during the first six months of 2001, as we
complete modifications to our existing systems and processes and we pursue
collection of the accounts receivable that were reserved. This expectation is
approximately $1.0 million to $1.5 million higher than what we estimate our
normal expenses will be, exclusive of the recently announced acquisitions.

  Depreciation and Amortization. Depreciation and amortization expense was $24.5
million in 2000, $17.3 million in 1999 and $5.4 million in 1998. Approximately
$5.1 million of the increase in 2000 as compared to 1999 is due to increased
amortization expense, primarily related to amortization of debt issue costs
associated with facilities put in place during the fourth quarter of 1999,
subsequent to the unauthorized trading losses. The remaining increase is
attributable to the Scurlock and West Texas Gathering System acquisitions which
were effective May 1, 1999 and July 1, 1999, respectively, as well as our 1999
and 2000 expansion capital additions. The increase in 1999 is due primarily to
the aforementioned acquisitions.

  Restructuring expense. We incurred a $1.4 million restructuring charge in
1999, primarily associated with severance-related expenses of 24 employees who
were terminated. As of December 31, 1999, all severance costs were paid and the
terminated employees were not employed by us.

  Interest expense. Interest expense was $28.7 million in 2000, $21.1 million in
1999 and $12.6 million in 1998. The increase in 2000 is primarily due to higher
interest rates as well as slightly higher debt balances. The increase in 1999 is
due to (1) interest associated with the debt incurred for the Scurlock and West
Texas Gathering System acquisitions, (2) a full year of interest for the All
American Pipeline acquisition, (3) an increase in interest related to hedged
inventory transactions and (4) an increase in interest rates as a result of the
unauthorized trading losses.

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

  We had suspended shipments of crude oil on this segment of the pipeline in
November 1999. At that time, we owned approximately 5.2 million barrels of crude
oil in the segment of the pipeline. We sold this crude oil from November 1999 to
February 2000 for net proceeds of approximately $100.0 million, which were used
for working capital purposes. We

                                       30

recognized gains of approximately $28.1 million and $16.5 million in 2000 and
1999, respectively, in connection with the sale of the linefill.

  Early extinguishment of debt. During 2000, we recognized extraordinary losses,
consisting primarily of unamortized debt issue costs, totaling $15.1 million
related to the permanent reduction of the All American Pipeline, L.P. term loan
facility and the refinancing of our credit facilities. In addition, interest and
other income for the year ended December 31, 2000, includes $9.7 million of
previously deferred gains from terminated interest rate swaps as a result of
debt extinguishment. The extraordinary item of $1.5 million in 1999 relates to
the write-off of certain debt issue costs and penalties associated with the
prepayment of debt.

 Segment Results

  Pipeline Operations. Gross margin from pipeline operations was $51.8 million
for the year ended December 31, 2000, compared to $58.0 million for 1999 and
$16.8 million for 1998. Gross margin from pipeline activities was negatively
impacted on a comparative basis in 2000 due to the sale of the California to
West Texas portion of the All American Pipeline, decreased tariff volumes from
California OCS production and slightly higher fuel and power charges in 2000.
These decreases in 2000 were partially offset by increased margins from the
Scurlock and West Texas gathering system acquisitions in mid-1999. The increase
in 1999 resulted primarily from twelve months of results from the All American
Pipeline in 1999 versus five months in 1998, increased margins from our pipeline
merchant activities, and to the two 1999 acquisitions.

  The margin between revenue and direct cost of crude purchased from our
pipeline margin activities was $21.1 million for the year ended December 31,
2000, compared to $35.6 million and $3.9 million for 1999 and 1998,
respectively. Pipeline tariff revenues were approximately $47.0 million for the
year ended December 31, 2000 compared to approximately $46.4 million for 1999
and approximately $19.0 million for 1998. Pipeline operations and maintenance
expenses were approximately $16.3 million, $24.0 million and $6.1 million for
the years ended December 31, 2000, 1999 and 1998, respectively.

  Average daily pipeline volumes totaled 241,000 barrels per day, 218,000
barrels per day and 163,000 barrels per day in 2000, 1999 and 1998,
respectively. Volumes on the All American Pipeline decreased from an average of
157,000 barrels per day in 1999 to 134,000 barrels per day in 2000 due to the
reasons discussed above. All American's tariffs volumes attributable to
California OCS production were approximately 74,000 barrels per day in 2000
compared to 79,000 barrels per day in 1999. Volumes from the Santa Ynez and
Point Arguello fields, both offshore California, have steadily declined from
1995 through 2000. 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 $2.6 million. Tariff volumes shipped on the Scurlock and West
Texas gathering systems averaged 107,000 barrels per day and 61,000 barrels per
day in 2000 and 1999, respectively. The 1999 period includes volumes for
Scurlock effective May 1, 1999 and West Texas gathering system volumes effective
July 1, 1999.

  Gathering and Marketing Activities and Terminalling and Storage Activities.
Excluding the unauthorized trading losses, gross margin from gathering and
marketing and terminalling and storage activities was approximately $82.9
million for the year ended December 31, 2000, reflecting a 59% increase over the
$52.3 million reported for 1999 and a 282% increase over the  $21.7 million
reported for 1998. The increase in gross margin is primarily due to a full year
of results from the Scurlock acquisition and increased per barrel margins due to
the strong crude oil market in 2000. Gross revenues from gathering, marketing,
terminalling and storage activities were approximately $6.1 billion, $10.1
billion and $3.3 billion for the years ended December 31, 2000, 1999 and 1998,
respectively. The decrease in 2000 as compared to 1999 was primarily
attributable to lower buy/sell, exchange and bulk volumes, partially offset by
higher crude oil prices. The increase in 1999 as compared to 1998 was primarily
due to increased buy/sell, exchange, bulk and lease volumes, partially
attributable to the May 1999 Scurlock acquisition, as well as higher crude oil
prices.

  Lease gathering volumes averaged 262,000 barrels per day in 2000, 265,000
barrels per day in 1999 and 88,000 barrels per day in 1998. Bulk purchase
volumes averaged 28,000 barrels per day, 138,000 barrels per day and 98,000
barrels per day in 2000, 1999 and 1998, respectively. The decreases in 2000
compared to 1999 are due primarily to a significant amount of low margin barrels
that were phased out subsequent to the discovery of the trading losses,
partially offset by increased volumes attributable to the Scurlock acquisition,
which was effective May 1, 1999. The increase in 1999 compared to 1998 is due to
the Scurlock acquisition.

  In the period immediately following the disclosure of the unauthorized trading
losses, a significant number of our suppliers and trading partners reduced or
eliminated the open credit previously extended to us. Consequently, the amount
of letters of credit we needed to support the level of our crude oil purchases
then in effect increased significantly. In addition, the cost to us of obtaining
letters of credit increased under our credit facility. In many instances we
arranged for letters of

                                       31

credit to secure our obligations to purchase crude oil from our customers, which
increased our letter of credit costs and decreased our unit margins. In other
instances, primarily involving lower margin wellhead and bulk purchases, our
purchase contracts were terminated. We estimate that adjusted EBITDA and net
income was adversely affected by approximately $6.0 million in 2000 as a result
of the increase in letter of credit costs and reduced volumes. Currently, our
letter of credit requirement levels are lower than those levels existing prior
to the unauthorized trading losses.

  Terminal throughput, which includes both our Cushing and Ingleside terminals,
was 67,000, 83,000 and 80,000 barrels per day for the years ended December 31,
2000, 1999 and 1998, respectively. Storage leased to third parties averaged 1.8
million, 2.0 million and 1.2 million barrels per month for the same periods.

LIQUIDITY AND CAPITAL RESOURCES

 Recent Developments

  Consistent with our publicly announced intention to expand operations into
Canada, we are pursuing the acquisition of certain Canadian assets in two
separate transactions for aggregate consideration of approximately $200.0
million. Set forth below is a brief description of the acquisitions.

 Murphy Oil Company Ltd. Midstream Operations

  On March 1, 2001, we signed an agreement to purchase substantially all of the
crude oil pipeline, gathering, storage and terminalling assets of Murphy for
approximately $155.0 million in cash, plus an additional cash payment, to be
determined prior to closing in accordance with the agreement, for excess
inventory in the systems (estimated to be approximately $5.0 million). The
principal assets to be acquired include approximately 450 miles of crude oil and
condensate transmission mainlines and associated gathering and lateral lines,
and approximately 1.1 million barrels of crude oil storage and terminalling
capacity located primarily in Kerrobert, Saskatchewan, approximately 200,000
barrels of linefill, as well as a currently inactive 108-mile mainline system
and 121 trailers used primarily for crude oil transportation.

  Murphy has agreed to continue to transport production from fields currently
delivering crude oil to these pipeline systems, under a new long-term contract.
The current volume is approximately 11,000 barrels per day. The pipeline systems
transport approximately 200,000 barrels per day of light, medium and heavy
crudes, as well as condensate.

 Canadian Marketing Assets

  We have entered into a letter of intent to purchase the assets of a Canadian
marketing company. The expected purchase price is approximately $43.0 million,
of which approximately $18.0 million will be subject to certain performance
targets. The marketing company currently generates annual EBITDA of
approximately $10.0 million, gathering approximately 75,000 barrels per day of
crude oil and marketing approximately 26,000 barrels per day of natural gas
liquids. Tangible assets include a crude oil handling facility, a 100,000 barrel
tank facility and working capital of approximately $8.5 million.

  Initial financing for the acquisitions will be provided via an expansion of
our existing revolving credit, letter of credit and inventory facility. The
expanded facility will initially be underwritten by Fleet Boston and will
consist of a $100.0 million five-year term loan and a $30.0 million revolving
credit facility that will expire in April 2005. Consistent with our stated
policy of maintaining a strong capital structure by funding acquisitions with a
balance of debt and equity, we intend to refinance a portion of our bank
facility with proceeds from future bond and equity financings.

  We intend to create and establish a midstream crude oil presence in Canada
that is similar to our existing operations in the U.S. By using the knowledge
and skills developed in our U.S. operations, we hope to generate attractive
financial returns in the Canadian market through exploiting existing
inefficiencies, while attempting to improve revenues and margins on our acquired
pipeline, terminalling and gathering assets. These assets complement our current
activities and enhance our ability to service the needs of refiners in the U.S.
Midwest. The completion of both transactions, while independent of one another,
will provide us with direct access to substantial Canadian wellhead volumes via
gathering and pipeline systems and strategically located terminal and storage
assets.

 General

  Cash generated from operations and our credit facilities are our primary
sources of liquidity. At December 31, 2000, we had working capital of
approximately $47.1 million and approximately $80.0 million of availability
under our revolving credit facility. In connection with the previously discussed
Canadian acquisitions, our existing credit facilities will be

                                       32

expanded to $830.0 million. See "Credit Agreements." Consistent with our stated
policy of maintaining a strong capital structure by funding acquisitions with a
balance of debt and equity, we intend to refinance a portion of our credit
facilities with proceeds from future bond and equity financings.

  We believe that we have sufficient liquid assets, cash from operations and
borrowing capacity under our credit agreements to meet our financial
commitments, debt service obligations, contingencies and anticipated capital
expenditures.

 Cash Flows

                                            YEAR ENDED DECEMBER 31,
                                    --------------------------------------
       (in millions)                    2000         1999         1998
       -------------------------------------------------------------------
                                                                (COMBINED)
       Cash provided by (used in):
          Operating activities          $ (33.5)     $ (71.2)     $  28.6
          Investing activities            211.0       (186.1)      (402.7)
          Financing activities           (227.8)       305.6        387.5
       -------------------------------------------------------------------

  Operating Activities. Net cash used in operating activities in 2000 and 1999
resulted primarily from the unauthorized trading losses. The losses were
partially offset by increased margins due to the Scurlock and West Texas
Gathering System acquisitions.

  Investing Activities. Net cash provided by investing activities for 2000
included approximately $224.0 million of proceeds from the sale of the All
American Pipeline and pipeline linefill offset by approximately $12.6 million of
capital expenditures. Capital expenditures for 2000 included approximately $10.8
million for expansion capital and $1.8 million for maintenance capital. Net cash
used in investing activities for 1999 included approximately $176.9 million for
acquisitions, primarily for the Scurlock and West Texas gathering system
acquisitions, $11.1 million for expansion capital and $1.7 million for
maintenance capital. Net cash used in investing activities for 1998 consisted
primarily of approximately $394.0 million for the purchase of the All American
Pipeline and SJV Gathering System.

  Financing activities. Cash used in financing activities in 2000 consisted
primarily of (1) net payments of $47.5 million of short-term and long-term debt,
(2) the repayment of subordinated debt of $114.0 million to our general partner
and (3) distributions to unitholders of $59.6 million. Proceeds used to reduce
the bank debt primarily came from the asset sales discussed above. Proceeds to
repay the $114.0 million of subordinated debt to our general partner came from
our revolving credit facility. Cash provided by financing activities in 1999 was
generated from net issuances of (1) $76.5 million in common and Class B units,
(2) $184.1 million of short-term and long-term debt and (3) $114.0 million of
two subordinated notes to our general partner. Financing activities for 1999
includes $51.7 million in distributions to unitholders. Cash inflows from
financing activities during 1998 included (1) $283.8 million from the net
issuance of short-term and long-term debt and (2) a capital contribution of
approximately $113.7 million from our general partner primarily in connection
with the acquisition of the All American Pipeline and SJV Gathering System.

  In October 1999, we completed a public offering of an additional 2,990,000
common units, representing limited partner interests, at $18.00 per unit. Net
proceeds, including our general partners' contribution, were approximately $51.3
million after deducting underwriters' discounts and commissions and offering
expenses of approximately $3.1 million. The proceeds, together with our general
partner's capital contribution of approximately $0.5 million to maintain its 2%
general partner interest, were used to reduce outstanding debt.

 Capital Expenditures

  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, bank borrowings and
the sale of additional common units. We intend to make aggregate capital
expenditures of approximately $7.0 million in 2001 and believe that we will have
sufficient cash from working capital, cash flow and availability under our
revolving credit facility under our bank credit agreement. We estimate that
capital expenditures necessary to maintain our existing asset base at current
operating levels will be approximately $4.0 million to $5.0 million each year.

                                       33

 Commitments

  The aggregate amounts of maturities of all long-term indebtedness for the next
five years at December 31, 2000 are: 2005 - $320.0 million. This amount is due
under our revolving credit facility and reflects the February 2001 amendments to
our revolving credit facility.

  We will distribute 100% of our available cash within 45 days after the end of
each quarter to unitholders of record, and to our general partner. Available
cash is generally defined as all cash and cash equivalents on hand at the end of
the quarter less reserves established for future requirements. Minimum quarterly
distributions are $0.45 for each full fiscal quarter. Distributions of available
cash to the holders of subordinated units are subject to the prior rights of the
holders of common units to receive the minimum quarterly distributions for each
quarter during the subordination period, and to receive any arrearages in the
distribution of minimum quarterly distributions on the common units for prior
quarters during the subordination period. The expiration of the subordination
period will generally not occur prior to December 31, 2003. There were no
arrearages on common units at December 31, 2000. On February 14, 2001, we paid a
cash distribution of $0.4625 per unit on our outstanding common units, Class B
units and subordinated units. The distribution was paid to unitholders of record
on February 2, 2001 for the period October 1, 2000 through December 31, 2000.
The total distribution paid was approximately $16.3 million, with approximately
$7.5 million paid to our public unitholders and the remainder paid to us for our
limited and general partner interests.

  In connection with our crude oil marketing, we provide certain purchasers and
transporters with irrevocable standby letters of credit to secure their
obligation for the purchase of crude oil. Generally, these letters of credit are
issued for up to seventy day periods and are terminated upon completion of each
transaction. At December 31, 2000, we had outstanding letters of credit of
approximately $59.7 million. Such letters of credit are secured by our crude oil
inventory and accounts receivable.

  As is common within the industry, we have entered into various commitments and
agreements related to the marketing, transportation, terminalling and storage of
crude oil. It is management's belief that such commitments will be met without a
material adverse effect on our financial position, results of operations or cash
flows.

 Credit Agreements

  In May 2000, we entered into new bank credit agreements consisting of a $400.0
million senior secured revolving credit facility maturing in 2004 and a $300.0
million senior secured letter of credit and borrowing facility expiring in April
2003.  At December 31, 2000, $320.0 million was outstanding on the revolving
credit facility and $1.3 million in borrowings and $59.7 million in letters of
credit were outstanding under the letter of credit and borrowing facility. In
February 2001, our bank credit agreements were amended. The amount available
under the senior secured revolving credit facility was increased to $500.0
million and the maturity date was extended to April 2005. The amount available
under the senior secured letter of credit and borrowing facility was reduced to
$200.0 million and the expiration date was extended to April 2004. In addition,
the banks agreed to an amendment which will allow us to borrow an additional
$130.0 million under the terms of the senior secured revolving credit facility
to consummate the Canadian acquisitions. We have an underwritten commitment,
subject to certain conditions, for the $130.0 million.

  Our bank credit agreements currently consist of:

  .  a $500.0 million senior secured revolving credit, of which $492.0 million
     is currently available, facility which is secured by substantially all of
     our assets and matures in April 2005. No principal is scheduled for payment
     prior to maturity. The revolving credit facility bears interest at our
     option at either the base rate, as defined, plus an applicable margin, or
     LIBOR plus an applicable margin. We incur a commitment fee on the unused
     portion of the revolving credit facility.
  .  A $200.0 million senior secured letter of credit and borrowing facility,
     the purpose of which is to provide standby letters of credit to support the
     purchase and exchange of crude oil for resale and borrowings to finance
     crude oil inventory that has been hedged against future price risk. The
     letter of credit facility is secured by substantially all of our assets and
     has a sublimit for cash borrowings of $100.0 million to purchase crude oil
     that has been hedged against future price risk. The letter of credit
     facility expires in April 2004. Aggregate availability under the letter of
     credit facility for direct borrowings and letters of credit is limited to a
     borrowing base that is determined monthly based on certain of our current
     assets and current liabilities, primarily accounts receivable and accounts
     payable related to the purchase and sale of crude oil.

                                       34

  Our bank credit agreements 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;
  .  grant liens;
  .  sell assets;
  .  make investments;
  .  engage in transactions with affiliates;
  .  enter into prohibited contracts; and
  .  enter into a merger or consolidation.

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

  .  a current ratio (as defined) of 1.0 to 1.0;
  .  a debt coverage ratio which is not greater than 4.0 to 1.0 for the period
     from March 31, 2000, to March 31, 2002, and subsequently 3.75 to 1.0;
  .  an interest coverage ratio which is not less than 2.75 to 1.0; and
  .  a debt to capital ratio of not greater than 0.65 to 1.0.

  The consummation of the Canadian marketing company acquisition will result in
a change in the required debt coverage and debt to capital ratios to:

  .  a debt coverage ratio which is not greater than 4.25 to 1.0 through
     December 30, 2002 and 4.0 to 1.0 thereafter; and
  .  a debt to capital ratio of not greater than 0.67 to 1.0 through December
     30, 2002 and 0.65 to 1.0 thereafter.

  The consummation of the Murphy Acquisition, whether or not the Canadian
marketing company acquisition occurs, will result in a change in the required
debt coverage and debt to capital ratios to:

  .  a debt coverage ratio which is not greater than 4.75 to 1.0 through
     September 29, 2001, 4.50 to 1 from September 30, 2001 through June 29,
     2002, 4.25 to 1.0 from June 30, 2002 through December 30, 2002 and 4.0 to
     1.0 thereafter; and
  .  a debt to capital ratio of not greater than 0.73 to 1.0 prior to December
     30, 2002 and 0.65 to 1.0 thereafter.

  A default under our bank credit agreements would permit the lenders to
accelerate the maturity of the outstanding debt and to foreclose on the assets
securing the credit facilities. As long as we are in compliance with our bank
credit agreements, they do not restrict our ability to make distributions of
"available cash" as defined in our partnership agreement. We are currently in
compliance with the covenants contained in our credit agreements. Under the most
restrictive of these covenants, at December 31, 2000, we could have borrowed
up to $386.4 million under our secured revolving credit facility.

 Contingencies

  Following our announcement in November 1999 of our losses resulting from
unauthorized trading by a former employee, numerous class action lawsuits were
filed against us, certain of our general partner's officers and directors and in
some of these cases, our general partner and Plains Resources Inc. alleging
violations of the federal securities laws. In addition, derivative lawsuits were
filed in the Delaware Chancery Court against our general partner, its directors
and certain of its officers alleging the defendants breached the fiduciary
duties owed to us and our unitholders by failing to monitor properly the
activities of our traders. These suits have, for the most part, been settled.
See Item 3. - "Legal Proceedings".

  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.

                                       35

OUTLOOK

  As is common with most merchant activities, our ability to generate a profit
on our margin activities is not tied to the absolute level of crude oil prices
but is generated by the difference between the price paid and other costs
incurred in the purchase of crude oil and the price at which we sell crude oil.
The gross margin generated by tariff activities depends on the volumes
transported on the pipeline and the level of the tariff charged, as well as the
fixed and variable costs of operating the pipeline. These operations are
affected by overall levels of supply and demand for crude oil.

  Our operations will be impacted by higher fuel and power costs relating to our
pipeline and trucking operations. The increased costs will be offset by a 10%
increase in the tariff rate on the All American Pipeline effective January 1,
2001. Also, the crude oil market moved into contango in March 2001, which
generally means lower gross margin from our gathering and marketing activities
during this transition. However, this type of market creates other arbitrage
opportunities and an increase in the utilizations of our tankage at Cushing and
in the field. We believe, although there can be no assurance, that increased
profits from these opportunities will reduce the impact of the weaker gathering
and marketing markets.

  A significant portion of our gross margin is derived from the Santa Ynez and
Point Arguello fields located offshore California. Volumes received from the
Santa Ynez and Point Arguello fields have declined from 92,000 and 60,000
average daily barrels, respectively, in 1995 to 56,000 and 18,000 average daily
barrels, respectively, for the year ended December 31, 2000. We expect that
there will continue to be natural production declines from each of these fields
as the underlying reservoirs are depleted. As operator of Point Arguello, Plains
Resources is conducting additional drilling and other activities on this field,
but we cannot assure you that these activities will affect the production
decline. 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
$2.6 million.

RECENT ACCOUNTING PRONOUNCEMENTS

  In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
133. SFAS 133 was subsequently amended (i) in June 1999 by SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133" ("SFAS 137"), which deferred the
effective date of SFAS 133 to fiscal years beginning after June 15, 2000; and
(ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative Instruments
and Certain Hedge Activities," which amended certain provisions, inclusive of
the definition of the normal purchase and sale exclusion.  We have determined
that our physical purchase and sale agreements, which under SFAS 133 could be
considered derivatives, qualify for the normal purchase and sale exclusion.

  SFAS 133 requires that all derivative instruments be recorded on the balance
sheet at their fair value. Changes in the fair value of derivatives are recorded
each period in current earnings or other comprehensive income, depending on
whether a derivative is designated as part of a hedge transaction and, if so,
the type of hedge transaction. For fair value hedge transactions in which we are
hedging changes in the fair value of an asset, liability, or firm commitment,
changes in the fair value of the derivative instrument will generally be offset
in the income statement by changes in the fair value of the hedged item. For
cash flow hedge transactions, in which we are hedging the variability of cash
flows related to a variable-rate asset, liability, or a forecasted transaction,
changes in the fair value of the derivative instrument will be reported in other
comprehensive income, a component of partners' capital. The gains and losses on
the derivative instrument that are reported in other comprehensive income will
be reclassified as earnings in the periods in which earnings are affected by the
variability of the cash flows of the hedged item. The ineffective portion of all
hedges will be recognized in earnings in the current period.

  We have adopted SFAS 133, as amended, effective January 1, 2001. Our
implementation procedures identified all instruments in place at the adoption
date that are subject to the requirements of SFAS 133. Upon adoption, we
recorded a cumulative effect charge of $8.3 million in accumulated other
comprehensive income to recognize at fair value all derivative instruments that
were designated as cash flow hedging instruments and a cumulative effect gain of
$0.5 million to earnings. Correspondingly, an asset of $2.8 million and a
liability of $10.6 million have been established. Implementation issues continue
to be addressed by the FASB and any change to existing guidance might impact our
implementation. Adoption of this standard could increase volatility in earnings
and partners' capital through comprehensive income.

                                       36

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

  We are exposed to various market risks, including volatility in crude oil
commodity prices and interest rates. To manage such exposure, we monitor our
inventory levels, current economic conditions and our expectations of future
commodity prices and interest rates when making decisions with respect to risk
management. We do not enter into derivative transactions for speculative trading
purposes. Substantially all of our derivative contracts are exchanged or traded
with major financial institutions and the risk of credit loss is considered
remote.

  Commodity Price Risk. The fair value of outstanding derivative instruments and
the change in fair value that would be expected from a 10 percent price decrease
are shown in the table below (in millions):

                                                  DECEMBER 31,
                                     ---------------------------------------
                                            2000                 1999
                                     --------------------  -----------------
                                               EFFECT OF          EFFECT OF
                                                 10%                10%
                                       FAIR     Price      FAIR     Price
                                       VALUE   Decrease    VALUE   Decrease
                                     --------------------  -----------------
       Crude oil:
        Futures contracts              $(9.4)    $6.0         -      $(2.8)
        Swaps and options contracts        -        -      (0.6)      (0.1)

  The fair values of the futures contracts are based on quoted market prices
obtained from the NYMEX. The fair value of the swaps and option contracts are
estimated based on quoted prices from independent reporting services compared to
the contract price of the swap which approximate the gain or loss that would
have been realized if the contracts had been closed out at year end. All hedge
positions offset physical positions exposed to the cash market; none of these
offsetting physical positions are included in the above table. Price-risk
sensitivities were calculated by assuming an across-the-board 10 percent
decrease in price regardless of term or historical relationships between the
contractual price of the instruments and the underlying commodity price. In the
event of an actual 10 percent change in prompt month crude prices, the fair
value of our derivative portfolio would typically change less than that shown in
the table due to lower volatility in out-month prices.

  At December 31, 2000, our hedging activities included crude oil futures
contracts maturing through 2001, covering approximately 3.2 million barrels of
crude oil. Because such contracts are designated as hedges and correlate to
price movements of crude oil, any gains or losses resulting from market changes
will be largely offset by losses or gains on our hedged inventory or anticipated
purchases of crude oil. Such contracts resulted in a reduction in revenues of
$15.1 million and $17.8 million in 2000 and 1999. The offsetting gains from the
physical positions are not included in such amounts. The unrealized loss with
respect to such instruments at December 31, 2000 was $7.8 million.

  Interest Rate Risk. Our debt instruments are sensitive to market fluctuations
in interest rates. The table below presents principal payments and the related
weighted average interest rates by expected maturity dates for debt outstanding
at December 31, 2000. Our variable rate debt bears interest at LIBOR or prime
plus the applicable margin. The average interest rates presented below are based
upon rates in effect at December 31, 2000. The carrying value of variable rate
bank debt approximates fair value because interest rates are variable, based on
prevailing market rates (dollars in millions).

                                                      EXPECTED YEAR OF MATURITY
                                       -------------------------------------------------------------     FAIR
                                        2001     2002    2003     2004     2005    THEREAFTER  TOTAL     VALUE
                                       ------------------------------------------------------------------------
                                                                                
Liabilities:
  Short-term debt  - variable rate      $ 1.3    $   -   $   -   $    -    $   -   $   -      $  1.3    $  1.3
    Average interest rate                8.37%       -       -        -        -       -        8.37%
  Long-term debt - variable rate            -        -       -    320.0 (1)    -       -       320.0     320.0
    Average interest rate                   -        -       -     9.15%       -       -        9.15%

  (1) After the February 2001 amendments to our bank credit agreements, the expected year of maturity is 2005.

   At December31,, 1999, the carrying value of short-term debt of $58.7 million
and $424.1 million, respectively fair value.

                                       37

   Interest rate swaps and collars are used to hedge underlying debt obligtions.
These instruments hedge specific debt issuances and qualify for hedge
accounting. The interest rate differential is reflected as an adjustment to
interestexpense over the life of the instruments. At December 31, 2000, we had
interest rate swap and collar arrangements for an aggregate notional principal
amount of $215.0 million, for which we would pay approximately $0.6 million if
such arrangements were terminated as of such date. The adjustment to interest
expense resulting from interest rate swaps for the years ended December 31, 2000
and 1999 was a $0.1 million gain and a $0.1 million loss, respectively. These
instruments are based on LIBOR margins and provide for a floor of 5% and a
ceiling of 6.5% with an expiration date of February 2001 for $90.0 million
notional principal amount and a floor of 6% and a ceiling of 8% with an
expiration date of August 2002 for $125.0 million notional principal amount.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE

  None.

                                       38

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF OUR GENERAL PARTNER

PARTNERSHIP MANAGEMENT

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

  Two members of the board of directors of our general partner serve on a
conflicts committee that reviews specific matters that the board believes may
involve conflicts of interest between our general partner and Plains All
American Pipeline. The conflicts committee determines if the resolution of a
conflict of interest is fair and reasonable to us. The members of the conflicts
committee may not be officers or employees of our general partner or directors,
officers or employees of its affiliates. Any matters approved by the conflicts
committee will be conclusively deemed to be fair and reasonable to us, approved
by all of our partners, and not a breach by our general partner of any duties
owed to us. The members of the conflicts committee also serve with another
director on an audit committee, which reviews our external financial reporting,
recommends engagement of our independent auditors and reviews procedures for
internal auditing and the adequacy of our internal accounting controls.

  As is commonly the case with publicly-traded limited partnerships, we are
managed and operated by the officers and are subject to the oversight of the
directors of our general partner. Our operational personnel are employees of our
general partner.

  Some officers of our general partner may spend a substantial amount of time
managing the business and affairs of Plains Resources and its affiliates. These
officers may face a conflict regarding the allocation of their time between our
business and the other business interests of Plains Resources. Our general
partner intends to cause its officers to devote as much time to the management
of our business and affairs as is necessary for the proper conduct of our
business and affairs.

Directors and Executive Officers of our General Partner

  The following table sets forth certain information with respect to the
executive officers and members of the Board of Directors of our general partner.
Executive officers and directors are elected for one year terms.

      NAME                    AGE          POSITION WITH OUR GENERAL PARTNER
- ------------------------      ---     -----------------------------------------------------------------
                                       
Greg L. Armstrong              42     Chairman of the Board, Chief Executive Officer and Director
Harry N. Pefanis               43     President, Chief Operating Officer and Director
Phillip D. Kramer              45     Executive Vice President and Chief Financial Officer
George R. Coiner               50     Senior Vice President
Alfred A. Lindseth             31     Vice President - Administration
Tim Moore                      43     Vice President, General Counsel and Secretary
Mark F. Shires                 43     Vice President - Operations
Cynthia A. Feeback             43     Vice President - Accounting and Treasurer
Everardo Goyanes               56     Director and Member of Audit and Conflicts Committees
Robert V. Sinnott              51     Director and Member of Audit and Compensation
                                      Committees
Arthur L. Smith                48     Director and Member of Audit, Conflicts and Compensation
                                      Committees

  Greg L. Armstrong has served as Chairman of the Board, Chief Executive Officer
and Director of our general partner since its formation. In addition, he has
been President, Chief Executive Officer and Director of Plains Resources since
1992. 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.

                                       39

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

  Phillip D. Kramer has served as Executive Vice President and Chief Financial
Officer of our general partner since its formation. In addition, he has been
Executive Vice President and Chief Financial Officer of Plains Resources since
May 1998. 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 Vice President of our general partner
since its formation. In addition, he was Vice President of Plains Marketing &
Transportation Inc., a former midstream subsidiary of Plains Resources, from
November 1995 until our formation in 1998. Prior to joining Plains Marketing &
Transportation Inc., he was Senior Vice President, Marketing with Scurlock
Permian Corp.

  Alfred A. Lindseth has served as Vice President - Administration of our
general partner since March 2001. He served as Risk Manager of our general
partner from March 2000 until he was elected to his current position. 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.

  Tim Moore has served as Vice President, General Counsel and Secretary of our
general partner since May 2000. In addition, he has been Vice President, General
Counsel and Secretary of Plains Resources since May 2000. Prior to joining
Plains Resources, he served as General Counsel - Corporate of TransTexas Gas
Corporation. He previously was a corporate attorney with the Houston office of
Weil Gotshal & Manges. Mr. Moore also has seven years of industry experience as
a petroleum geologist.

  Mark F. Shires has served as Vice President - Operations of our general
partner since August 1999. He served as Manager of Operations for our general
partner from April 1999 until he was elected to his current position. 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 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.

  Cynthia A. Feeback has served as Vice President - Accounting and Treasurer
since May 2000 and Treasurer of our general partner since its formation. In
addition, she has been Vice President - Accounting and Assistant Treasurer of
Plains Resources since May 1999. She previously served Plains Resources as
Assistant Treasurer, Controller and Principal Accounting Officer from May 1998
to May 1999; Controller and Principal Accounting Officer from 1993 to 1998;
Controller from 1990 to 1993; and Accounting Manager from 1988 to 1990.

  Everardo Goyanes has served as a Director and a member of Audit and Conflicts
Committees since May 1999. Mr. Goyanes has been President and Chief Executive
Officer of Liberty Energy Holdings (an energy investment firm) since May 2000.
From 1998 to May 2000 he was a financial consultant specializing in natural
resources. From 1989 to 1998, he was Managing Director of the Natural Resources
Group of ING Baring Furman Selz (a commercial banking firm). He was a financial
consultant from 1987 to 1989 and was Vice President - Finance of Forest Oil
Corporation from 1983 to 1987.

  Robert V. Sinnott has served as a Director and a member of Audit and
Compensation Committees since September 1998. Mr. Sinnott has been Vice
President of Kayne Anderson Investment Management, Inc. (an investment
management firm) since 1992. 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 and a member of Audit, Conflicts and
Compensation Committees since February 1999. Mr. Smith is Chairman of John S.
Herold, Inc. (a petroleum research and consulting firm), a position he has held
since 1984. For the period from May 1998 to October 1998, he served as Chairman
and Chief Executive Officer of Torch Energy Advisors Incorporated. He is also a
director of Cabot Oil & Gas Corporation and Evergreen Resources, Inc.

                                       40

SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

  Section 16(a) of the Securities and Exchange Act of 1934 requires directors,
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
Exchange 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. 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 during
2000 our officers and directors complied with all filing requirements with
respect to our equity securities.

REIMBURSEMENT OF EXPENSES OF OUR GENERAL PARTNER AND ITS AFFILIATES

  Our general partner does not receive any management fee or other compensation
in connection with its management of Plains All American Pipeline. However, our
general partner and its affiliates, including Plains Resources, perform services
for us and are reimbursed by us for all expenses incurred on our behalf,
including the costs of employee, officer and director compensation and benefits
properly allocable to us, as well as all other expenses necessary or appropriate
to the conduct of our business and properly allocable to us. The 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.

ITEM 11.  EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

  We were formed in September 1998 but conducted no business until late November
1998. Accordingly, prior to 1999, no officer of our general partner received
salary and bonus compensation for services to the partnership in excess of
$100,000. Messrs. Armstrong, Pefanis, Kramer and Moore and Ms. Feeback are
compensated by Plains Resources and do not receive compensation from our general
partner with the exceptions of awards under the Long-Term Incentive Plan and the
Transaction Grant Agreements described below. However, we reimburse our general
partner and its affiliates, including Plains Resources for expenses incurred on
our behalf, including the costs of officer compensation properly allocable to
us.  See Item 13. - "Certain Relationships and Related Transactions -
Relationship with Plains Resources". The following table sets forth certain
compensation information for all executive officers of our general partner who
received salary and bonus compensation from our general partner in excess of
$100,000 in 2000 (the "Named Executive Officers").

                                              ANNUAL COMPENSATION        LONG-TERM
                                              -------------------       COMPENSATION      OTHER
  NAME AND PRINCIPAL POSITION         YEAR    SALARY       BONUS         LTIP PAYOUTS   COMPENSATION
- ------------------------------        ----    -------------------       -------------   -------------
                                                                              
George Coiner                         2000    $175,000      $500,700     $398,912   (1)    $10,500   (3)
    Senior Vice President             1999     180,956       295,000      167,073   (2)     10,000   (3)

Al Lindseth  (4)                      2000     109,308        55,000            -                -
    Vice President - Administration

Mark F. Shires                        2000     155,000       220,000            -           10,500   (3)
    Vice President - Operations       1999     160,792 (5)    77,500            -                -

- -------------------------
(1)  Represents the value of 16,667 common units plus distribution equivalent
     rights with respect to such units, which vested for 2000 under a
     Transaction Grant Agreement. See - "Transaction Grant Agreements" below.
(2)  Represents the value of 11,111 common units plus distribution equivalent
     rights with respect to such units, which vested for 1999 under a
     Transaction Grant Agreement.
(3)  Plains Resources matches 100% of our employees' contribution to its 401(k)
     Plan (subject to certain limitations in the plan), with such matching
     contribution being made 50% in cash and 50% in Plains Resources Common
     Stock (the number of shares for the stock match being based on the market
     value of the Common Stock at the time the shares are granted).
(4)  Mr. Lindseth was elected Vice President - Administration of our general
     partner in March 2001. He served as Risk Manager of our general partner
     from March 2000 until he was elected to his current position.
(5)  Includes $51,000 for consulting fees we paid to Mr. Shires prior to his
     becoming an employee of our general partner in April 1999.

                                       41

EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS

  Plains Resources has an employment agreement with Mr. Armstrong which expires
on March 1, 2002, and provides for a current base salary of $330,000 per year,
subject to annual review. If Mr. Armstrong's employment is terminated without
cause, he will be entitled to receive an amount equal to two times his annual
base salary. If his employment is terminated as a result of a change in control
of Plains Resources, he will be entitled to receive an amount equal to three
times the aggregate of his annual base salary and bonus. In either event, Mr.
Armstrong will be entitled to receive medical benefits for two years following
the date of his termination. Under Mr. Armstrong's agreement, a change in
control of Plains Resources is defined to include (i) the acquisition by an
entity or group of more than 25% of the voting stock of Plains Resources or (ii)
the directors in office on the date of the agreement ceasing to constitute a
majority of the Board of Directors of Plains Resources.

  Plains Resources also has an employment agreement with Mr. Pefanis, under
which Mr. Pefanis serves as Executive Vice President of Plains Resources as well
as President and Chief Operating Officer of our general partner and is
responsible for our overall operations. The employment agreement provides that
Plains Resources will not require Mr. Pefanis to engage in activities that
materially detract from his duties and responsibilities as an officer of our
general partner. The initial term of the employment agreement runs through
November 23, 2001, subject to annual extensions and includes confidentiality,
nonsolicitation and noncompete provisions, which, in general, will continue for
two years following termination of Mr. Pefanis' employment. The employment
agreement provides for an annual base salary of $235,000, subject to annual
review. If Mr. Pefanis' employment is terminated without cause, he will be
entitled to receive an amount equal to two times his base salary. Upon a Change
in Control of Plains Resources or a Marketing Operations Disposition (as such
terms are defined in the employment agreement), the term of the employment
agreement will be automatically extended for three years, and if Mr. Pefanis'
employment is terminated during the one-year period following either event by
him for a Good Reason or by Plains Resources other than for death, disability or
Cause (as such terms are defined in the employment agreement), he will be
entitled to a lump sum severance amount equal to three times the sum of (1) his
highest rate of annual base salary and (2) the largest annual bonus paid during
the three preceding years.

LONG-TERM INCENTIVE PLAN

  Our general partner has adopted the Plains All American Inc. 1998 Long-Term
Incentive Plan for employees and directors of our general partner and its
affiliates who perform services for us. The Long-Term Incentive Plan consists of
two components, a restricted unit plan and a unit option plan. The Long-Term
Incentive Plan currently permits the grant of restricted units and unit options
covering an aggregate of 975,000 common units. The plan is administered by the
Compensation Committee of our general partner's board of directors.

  Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the
grantee to receive a common unit upon the vesting of the phantom unit. As of
March 15, 2001, an aggregate of approximately 610,100 restricted units have been
granted to employees of our general partner. Grants made include 60,000, 30,000,
15,000 and 30,000 units to Messrs. Pefanis, Coiner, Lindseth and Shires,
respectively. In addition, 15,000 restricted units have been granted to non-
employee directors of our general partner. The Compensation Committee may, in
the future, make additional grants under the plan to employees and directors
containing such terms as the Compensation Committee shall determine. In general,
restricted units granted to employees during the subordination period will vest
only upon, and in the same proportions as, the conversion of the subordinated
units to common units. Grants made to non-employee directors of our general
partner are eligible to vest prior to termination of the subordination period.
See "- Compensation of Directors" below for the vesting provisions of grants
made to non-employee directors.

  If a grantee terminates employment or membership on the board for any reason,
the grantee's restricted 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, common units already owned by our general partner,
common units acquired by our general partner directly from us or any other
person, or any combination of the foregoing. Our general partner will be
entitled to reimbursement by us for the cost incurred in acquiring common units.
If we issue new common units upon vesting of the restricted units, the total
number of common units outstanding will increase. Following the subordination
period, the Compensation Committee, in its discretion, may grant tandem
distribution equivalent rights with respect to restricted units.

  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.

                                       42

  Unit Option Plan. The Unit Option 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 equal to the fair
market value of the units on the date of grant. Unit options granted during the
subordination period will become exercisable automatically upon, and in the same
proportions as, the conversion of the subordinated units to common units, unless
a later vesting date is provided.

  Upon exercise of a unit option, our general partner will deliver common units
acquired by it in the open market, purchased directly from us or any other
person, or use 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 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.

  The unit option plan has been designed to furnish additional compensation to
employees and directors and to align their economic interests with those of the
common unitholders. Our general partner's board of directors in its discretion
may terminate the Long-Term Incentive Plan at any time with respect to any
common units for which a grant has not yet been made. Our general partner's
board of directors also has the right to alter or amend the Long-Term Incentive
Plan or any part of the plan from time to time, including 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.

TRANSACTION GRANT AGREEMENTS

  In addition to the grants made under the Restricted Unit Plan described above,
our general partner, at no cost to us, agreed to transfer approximately 400,000
of its affiliates' common units (including distribution equivalent rights
attributable to such units) to certain key officers and employees of our general
partner and its affiliates. Generally, under these grants, the common units vest
based on attaining a targeted operating surplus for a given year. Approximately
75,000 and 6,000 of the common units vest for 2001 and 2002, respectively, if
the operating surplus generated in each year equals or exceeds the amount
necessary to pay the minimum quarterly distributions on all outstanding common
units and the related distribution on our general partner interest.  If a
tranche of common units does not vest for a particular year due to a common unit
arrearage, such common units will vest at the time the common unit arrearages
for such year have been paid. In addition, approximately 58,000 and 11,000 of
the common units vest for 2001and 2002, respectively, if the operating surplus
generated in such year exceeds the amount necessary to pay the minimum quarterly
distributions on all outstanding common units and subordinated units and the
related distributions on our general partner interest. Approximately 69,000 and
113,000 (excluding approximately 20,000 units withheld for payment of federal
income taxes) of the units vested for 1999 and 2000, respectively and
approximately 47,000 common units remain unvested as no distribution on the
subordinated units was made for the fourth quarter of 1999. Any common units
remaining unvested shall vest upon, and in the same proportion as, the
conversion of subordinated units to common units. Distribution equivalent rights
are paid in cash at the time of the vesting of the associated common units.
Notwithstanding the foregoing, all common units become vested if Plains All
American Inc. is removed as our general partner prior to January 1, 2002.

  The compensation expense incurred in connection with these grants will be
funded by our general partner, without reimbursement by us. Under these grants,
75,000 common units were allocated to each of Messrs. Armstrong and Pefanis, and
50,000 common units were allocated to Mr. Coiner.

COMPENSATION OF DIRECTORS

  Each director of our general partner who is not an employee of our general
partner or Plains Resources is paid an annual retainer fee of $20,000, an
attendance fee of $2,000 for each board meeting he attends (excluding telephonic
meetings), an attendance fee of $500 for each committee meeting or telephonic
board meeting he attends plus reimbursement for related out-of-pocket expenses.
In 2000, each director (other than Messrs. Armstrong and Pefanis) received a
grant of 5,000 restricted units under our Long-Term Incentive Plan. The
restricted units under these grants generally vest in equal installments in
2001, 2002, 2003 and 2004 if the operating surplus generated in the prior year
exceeds the amount necessary to pay the minimum quarterly distributions on all
outstanding common units and subordinated units and the related distributions on
our general partner interest. Also in 2000, Messrs. Goyanes and Smith each
received $25,000 for their service on a special committee of the Board of
Directors of our general partner. Messrs. Armstrong and Pefanis, as officers of
our general partner, are otherwise

                                       43

compensated for their services to our general partner and therefore receive no
separate compensation for their services as directors of our general partner.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

  The following table sets forth the beneficial ownership of units held by
beneficial owners of 5% or more of the units, by directors and officers of our
general partner and by all directors and executive officers of our general
partner as a group as of March 15, 2001.

                                                    PERCENTAGE              PERCENTAGE                   PERCENTAGE
                                                       OF                      OF                           OF          PERCENTAGE
                                    COMMON            COMMON     COMMON       CLASS B   SUBORDINATED     SUBORDINATED       OF
NAME OF BENEFICIAL OWNER             UNITS            UNITS       UNITS        UNITS       UNITS            UNITS      TOTAL UNITS
- ----------------------------     --------------     ----------  ----------   ---------- -------------    ------------  ------------
                                                                                                
Plains Resources Inc. (1)        6,791,816   (3)        29.5%   1,307,190      100.0%    10,029,619           100%         52.7%
Plains All American Inc. (2)     6,791,816   (3)        29.5%   1,307,190      100.0%    10,029,619           100%         52.7%
Goldman, Sachs & Co.             1,412,575   (4)         6.1%           -          -              -             -           4.1%
Greg L. Armstrong                   95,000   (3)          (7)           -          -              -             -            (7)
Harry N. Pefanis                   142,900   (3)(5)       (7)           -          -              -             -            (7)
George R. Coiner                    79,976   (3)(5)       (7)           -          -              -             -            (7)
Al Lindseth                         15,000   (5)          (7)           -          -              -             -            (7)
Mark F. Shires                      30,000   (5)          (7)           -          -              -             -            (7)
Everardo Goyanes                     5,000   (6)          (7)           -          -              -             -            (7)
Robert V. Sinnot                    10,000   (6)          (7)           -          -              -             -            (7)
Arthur L. Smith                     12,500   (6)          (7)           -          -              -             -            (7)
All directors and executive
 officers as a group
 (11 persons)                      434,476           1.9% (8)           -          -              -             -       1.3% (8)

- -------------------------
(1)  Plains Resources Inc. is the sole stockholder of Plains All American Inc.,
     our general partner. The address of Plains Resources Inc. is 500 Dallas,
     Suite 700, Houston, Texas 77002.
(2)  The address of Plains All American Inc. is 500 Dallas, Suite 700, Houston,
     Texas 77002. The record holder of such common units and subordinated units
     is PAAI LLC, a wholly owned subsidiary of Plains All American Inc., whose
     address is 500 Dallas, Suite 700, Houston, Texas 77002.
(3)  Includes 197,220 common units owned by affiliates of our general partner to
     be transferred to employees pursuant to transaction grant agreements,
     subject to certain vesting conditions. The recipients and their initial
     grants included: Mr. Armstrong - 75,000 (33,333 units currently vested);
     Mr. Pefanis - 75,000 (37,567 units currently vested); Mr. Coiner - 50,000
     (23,754 units currently vested); Mr. Kramer - 30,000 (7,600 units currently
     vested) and Ms. Feeback - 10,000 (3,334 units currently vested). See Item
     11. - "Executive Compensation - Transaction Grant Agreements".
(4)  The address for Goldman, Sachs & Co. and its parent, the Goldman Sachs
     Group, Inc., is 85 Broad Street, New York, New York 10004. Goldman, Sachs &
     Co., a broker/dealer, and its parent, the Goldman Sachs Group, Inc., are
     deemed to have shared voting power and shared disposition power over
     1,412,575 common units owned by their customers.
(5)  Includes the following unvested common units issuable under the Long-Term
     Incentive Plan to: Mr. Pefanis - 60,000, Mr. Coiner - 30,000, Mr. Lindseth
     - 15,000 and Mr. Shires - 30,000. See Item 11. - "Executive Compensation -
     Long-Term Incentive Plan."
(6)  Includes 5,000 unvested restricted units issuable to each of Messrs.
     Goyanes, Sinnott and Smith under the Long-Term Incentive Plan. See Item 11.
     -"Executive Compensation - Compensation of Directors."
(7)  Less than one percent.
(8)  Assumes the vesting of the units granted pursuant to the transaction grant
     agreements and under the long-term incentive plan as described in footnotes
     (3), (5) and (6) above to the named officers and directors. See Item 11.
     "Executive Compensation - Long-Term Incentive Plan" for vesting conditions
     of these grants.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

RIGHTS OF OUR GENERAL PARTNER

  Our general partner and its affiliates own 8,099,006 common units, including
1,307,190 Class B common units, and 10,029,619 subordinated units, representing
an aggregate 52.7% of the total limited partner interests in Plains All American
Pipeline. In addition, our general partner owns an aggregate 2% general partner
interest in Plains All American Pipeline and the operating partnerships on a
combined basis. Through our general partner's ability, as general partner, to
manage and operate Plains All American Pipeline and the ownership of 8,099,006
common units, including 1,307,190 Class B common units, and all of the
outstanding subordinated units by our general partner and its affiliates
(effectively giving our general partner the ability to veto certain actions of
Plains All American Pipeline), our general partner has the ability to control
the management of Plains All American Pipeline.

                                       44

RELATIONSHIP WITH PLAINS RESOURCES

 General

  Plains Resources controls our general partner, which is its wholly owned
subsidiary. We have extensive ongoing relationships with Plains Resources. These
relationships include but are not limited to:

  .  an Omnibus Agreement that provides for (1) the resolution of certain
     conflicts arising from the fact that we and Plains Resources conduct
     related businesses and (2) our general partner's indemnification of us for
     certain matters; and

  .  a Marketing Agreement with Plains Resources that provides for the marketing
     of Plains Resources' equity crude oil production.

  In November 2000, Plains Resources announced that it is evaluating strategic
restructuring alternatives intended to optimize the value and value-creating
ability of each of its upstream and midstream business segments. The
alternatives include, but are not limited to, a spin off or split off of the
upstream segment or midstream segment, a spin off or special dividend of certain
of our units and potential asset sales. Any modifications to the existing
structure will depend on a number of factors including tax efficiency, critical
mass and other considerations. Accordingly, there can be no assurance that any
modifications will be made.

 Transactions with Affiliates

  For the year ended December 31, 2000, Plains Resources produced approximately
26,000 barrels per day that were subject to the Marketing Agreement. We paid
approximately $244.9 million for such production and recognized profits of
approximately $1.7 million under the terms of that agreement.

  Our general partner has sole responsibility for conducting our business and
managing our operations and owns all of the incentive distribution rights. Some
of the senior executives who currently manage our business also manage and
operate the business of Plains Resources. Our general partner does not receive
any management fee or other compensation in connection with its management of
our business, but it is reimbursed for all direct and indirect expenses incurred
on our behalf. For the year ended December 31, 2000, our general partner and its
affiliates incurred $63.8 million of direct and indirect expenses on our behalf.
Of this amount, $165,000 and $212,000 represented reimbursement for the services
of Messrs. Armstrong and Pefanis, respectively, as officers of our general
partner.

  In December 1999, following the losses we incurred as a result of the
unauthorized trading activity by a former employee, our general partner loaned
us approximately $114.0 million. This subordinated debt was repaid in May 2000.
We paid $3.3 million in 2000 for interest on this loan. Funding to our general
partner for these loans was provided by Plains Resources. See Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources".

 Indemnity from Our General Partner

  In connection with the acquisition of the All American Pipeline and the SJV
Gathering System in July 1998, Wingfoot agreed to indemnify our general partner
for certain environmental and other liabilities. The indemnity is subject to
limits of:

   .  $10.0 million with respect to matters of corporate authorization and title
      to shares;
   .  $21.5 million with respect to condition of rights-of-way, lease rights and
      undisclosed liabilities and litigation; and
    . $30.0 million with respect to environmental liabilities resulting from
      certain undisclosed and pre-existing conditions.

  Wingfoot has no liability, however, until the aggregate amount of losses with
respect to each such category exceeds  $1.0 million. These indemnities were in
effect until July 2000, with the exception of the environmental indemnity, which
will remain in effect until July 2001. However, upon the transfer to an
unaffiliated third party of a major portion of the assets acquired from
Wingfoot, the indemnities automatically terminate. The environmental indemnity
is also subject to certain sharing ratios, which change, based on whether the
claim is made in the first, second or third year of the indemnity as well as the
amount of such claim. We have also agreed to be solely responsible for the
cumulative aggregate amount of losses resulting from the oil leak from the All
American Pipeline to the extent such losses do not exceed $350,000. Any costs in
excess of $350,000 will be applied to the $1.0 million deductible for the
Wingfoot environmental indemnity. Our general partner has agreed to indemnify us
for environmental and other liabilities to the extent it is indemnified by
Wingfoot.  However, if the sale of the linefill from the All American Pipeline
and the subsequent sale of such pipeline to EPNG Pipeline

                                       45

Company are construed to constitute a sale of a major portion of the assets
acquired from Wingfoot, the indemnities by Wingfoot will terminate. See Items 1.
and 2. - "Business and Properties - Acquisitions and Dispositions - All American
Pipeline Linefill Sale and Asset Disposition".

  Plains Resources has agreed to indemnify us for environmental liabilities
related to the assets of the our predecessor transferred to us that arose prior
to closing and are discovered within three years after closing (excluding
liabilities resulting from a change in law after closing). Plains Resources'
indemnification obligation is capped at $3.0 million.

                                       46

                                    PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

   See "Index to Consolidated Financial Statements" set forth on Page F-1.

(a) (3)  EXHIBITS

   3.1   --  Second Amended and Restated Agreement of Limited Partnership of
             Plains All American Pipeline, L.P. dated as of November 23, 1998
             (incorporated by reference to Exhibit 3.1 to Annual Report on Form
             10-K for the Year Ended December 31, 1998).

   3.2   --  Amended and Restated Agreement of Limited Partnership of Plains
             Marketing, L.P. dated as of November 23, 1998 (incorporated by
             reference to Exhibit 3.2 to Annual Report on Form 10-K for the Year
             Ended December 31, 1998).

   3.3   --  Amended and Restated Agreement of Limited Partnership of All
             American Pipeline, L.P. dated as of November 23, 1998 (incorporated
             by reference to Exhibit 3.3 to Annual Report on Form 10-K for the
             Year Ended December 31, 1998).

   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   --  Amendment No. 1 to the Second Amended and Restated Agreement of
             Limited Partnership of Plains All American Pipeline L.P. dated as
             of May 12, 1999 (incorporated by reference to Exhibit 3.8 to
             Quarterly Report on Form 10-Q for the Quarter Ended June 30, 1999).

   3.8   --  Amendment No. 2 to the Second Amended and Restated Agreement of
             Limited Partnership of Plains All American Pipeline L.P. dated as
             of May 12, 1999 (incorporated by reference to Exhibit 3.1 to
             Quarterly Report on Form 10-Q for the Quarter Ended September 30,
             2000).

  10.01  --  Contribution, Conveyance and Assumption Agreement among Plains All
             American Pipeline, L.P. and certain other parties dated as of
             November 23, 1998 (incorporated by reference to Exhibit 10.03 to
             Annual Report on Form 10-K for the Year Ended December 31, 1998).

**10.02  --  Plains All American Inc., 1998 Long-Term Incentive Plan
             (incorporated by reference to Exhibit 10.04 to Annual Report on
             Form 10-K for the Year Ended December 31, 1998).

**10.03  --  Plains All American Inc., 1998 Management Incentive Plan Plains All
             American Inc., 1998 Long-Term Incentive Plan (incorporated by
             reference to Exhibit 10.05 to Annual Report on Form 10-K for the
             Year Ended December 31, 1998).

**10.04  --  Employment Agreement between Plains Resources Inc. and Harry N.
             Pefanis dated as of November 23, 1998 (incorporated by reference to
             Exhibit 10.06 to Annual Report on Form 10-K for the Year Ended
             December 31, 1998).

  10.05  --  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).

  10.06  --  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).

                                       47

  10.07  --  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).

  10.08  --  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).

**10.09  --  Form of Transaction Grant Agreement (Payment on Vesting)
             (incorporated by reference to Exhibit 10.12 to Registration
             Statement, file No. 333-64107).

  10.10  --  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).

  10.11  --  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).

  10.12  --  Asset Sales Agreement between Chevron Pipe Line Company and Plains
             Marketing, L.P. dated as of April 16, 1999 (incorporated by
             reference to Exhibit 10.17 to Quarterly Report on Form 10-Q for the
             Quarter Ended March 31, 1999).

**10.13  --  Transaction Grant Agreement with Greg L. Armstrong (incorporated by
             reference to Exhibit 10.20 to Registration Statement on Form S-1,
             file no. 333-86907)

  10.14  --  Pipeline Sale and Purchase Agreement dated January 31, 2000, among
             Plains All American Pipeline, L.P., All American Pipeline, L.P., El
             Paso Natural Gas Company and El Paso Pipeline Company (incorporated
             by reference to Exhibit 10.27 to Annual Report on Form 10-K for the
             Year Ended December 31, 1999).

  10.15  --  Credit Agreement [Letter of Credit and Hedged Inventory Facility]
             dated May 8, 2000, among Plains Marketing, L.P, All American
             Pipeline, L.P., Plains All American Pipeline, L.P., and Fleet
             National Bank and certain other lenders (incorporated by reference
             to Exhibit 10.01 to the Quarterly Report on Form 10-Q for the
             Quarter Ended March 31, 2000).

  10.16  --  Credit Agreement [Revolving Credit Facility] dated May 8, 2000,
             among Plains Marketing, L.P, All American Pipeline, L.P., Plains
             All American Pipeline, L.P., and Fleet national Bank and certain
             other lenders (incorporated by reference to Exhibit 10.02 to the
             Quarterly Report on Form 10-Q for the Quarter Ended March 31,
             2000).

* 10.17  --  First Amendment to Credit Agreement [Letter of Credit and
             Hedged Inventory Facility] dated as of February 26, 2001.

* 10.18  --  First Amendment to Credit Agreement [Revolving Credit
             Facility] dated as of February 26, 2001.

* 21.1   --  Subsidiaries of the Registrant.

* 23.1   --  Consent of PricewaterhouseCoopers LLP.

- ----------------------
*   Filed herewith
**  Management contract or compensatory plan or arrangement

(b)  REPORTS ON FORM 8-K

     A Current Report on Form 8-K was filed on December 7, 2000, in connection
     with the announcement that Plains Resources Inc. would be evaluating
     strategic restructuring alternatives intended to optimize the value and
     value-creating ability of each of its upstream and midstream business
     segments.

                                       48

                                   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 ALL AMERICAN INC.,
                                      Our General Partner

Date: April 2, 2001             By:  /s/  Phillip D. Kramer
                                     ----------------------------------------
                                      Phillip D. Kramer, Executive Vice
                                      President and
                                      Chief Financial Officer

  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.

Date: April 2, 2001             By:  /s/ Greg L. Armstrong
                                     ----------------------------------------
                                     Greg L. Armstrong, Chairman of the Board,
                                     Chief Executive Officer and Director of
                                     our General Partner (Principal Executive
                                     Officer)

Date: April 2, 2001             By:  /s/ Harry N. Pefanis
                                     ----------------------------------------
                                     Harry N. Pefanis, President, Chief
                                     Operating Officer
                                     and Director of our General Partner

Date: April 2, 2001             by:  /s/ Phillip D. Kramer
                                     ----------------------------------------
                                     Phillip D. Kramer, Executive Vice
                                     President and
                                     Chief Financial Officer (Principal
                                     Financial Officer) of
                                     our General Partner

Date: April 2, 2001             By:  /s/ Cynthia A. Feeback
                                     ----------------------------------------
                                     Cynthia A. Feeback, Vice President -
                                     Accounting (Principal Accounting Officer)
                                     of our General Partner

Date: April 2, 2001             By:  /s/ Everardo Goyanes
                                     ----------------------------------------
                                     Everardo Goyanes, Director of our General
                                     Partner

Date: April 2, 2001             By:  /s/ Robert V. Sinnott
                                     ----------------------------------------
                                     Robert V. Sinnott, Director of our General
                                     Partner

Date: April 2, 2001             By:  /s/ Arthur L. Smith
                                     ----------------------------------------
                                     Arthur L. Smith, Director of our General
                                     Partner

                                       49

                       PLAINS ALL AMERICAN PIPELINE, L.P.
            INDEX TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

                                                                                                           Page
                                                                                                           ----

Financial Statements

  Report of Independent Accountants.....................................................................   F-2

  Report of Independent Accountants.....................................................................   F-3

  Consolidated Balance Sheets as of December 31, 2000 and 1999..........................................   F-4

  Consolidated and Combined Statements of Operations:

    For the years ended December 31, 2000 and 1999

    For the period from inception (November 23,1998) to December 31, 1998 and

    For the period from January 1, 1998 to November 22, 1998 (Predecessor)..............................   F-5

  Consolidated and Combined Statements of Cash Flows:

    For the years ended December 31, 2000 and 1999

    For the period from inception (November 23,1998) to December 31, 1998 and

    For the period from January 1, 1998 to November 22, 1998 (Predecessor)..............................   F-6

  Consolidated Statements of Changes in Partners' Capital for the period from inception (November 23,

    1998) to December 31, 1998 and for the years ended December 31, 1999 and 2000.......................   F-7

  Notes to Consolidated and Combined Financial Statements...............................................   F-8

All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.

                                      F-1

                       REPORT OF INDEPENDENT ACCOUNTANTS

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

In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of changes in partners' capital and of
cash flows present fairly, in all material respects, the financial position of
Plains All American Pipeline, L.P. and its subsidiaries (the "Partnership") at
December 31, 2000 and 1999, and the results of their operations and their cash
flows for each of the two years in the period ended December 31, 2000 and the
period from inception (November 23, 1998) to December 31, 1998 in conformity
with accounting principles generally accepted in the United States of America.
These financial statements are the responsibility of the Partnership'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 auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit 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.

PricewaterhouseCoopers LLP

Houston, Texas
March 22, 2001

                                      F-2

                       REPORT OF INDEPENDENT ACCOUNTANTS

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

In our opinion, the accompanying combined statements of operations and cash
flows of the Plains Midstream Subsidiaries, the predecessor entity of Plains All
American Pipeline L.P., present fairly, in all material respects, the combined
results of their operations and their cash flows for the period from January 1,
1998 to November 22, 1998 in conformity with accounting principles generally
accepted in the United States of America. These financial statements are the
responsibility of the Plains Midstream Subsidiaries' management; our
responsibility is to express an opinion on these financial statements based on
our audit. We conducted our audit of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
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 audit provides a
reasonable basis for our opinion.

PricewaterhouseCoopers LLP

Houston, Texas
March 22, 2001

                                      F-3

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
                         CONSOLIDATED BALANCE SHEETS
                       (in thousands, except unit data)

                                                                                     DECEMBER 31,
                                                                              -------------------------
                                                                                2000             1999
                                                                              --------          -------
                                                                                        
                              ASSETS

CURRENT ASSETS
Cash and cash equivalents                                                     $  3,426      $   53,768
Accounts receivable and other                                                  347,698         508,920
Inventory                                                                       46,780          34,826
Assets held for sale (Note 5)                                                        -         141,486
                                                                              --------      ----------
Total current assets                                                           397,904         739,000
                                                                              --------      ----------
PROPERTY AND EQUIPMENT                                                         467,619         454,878
Less allowance for depreciation and amortization                               (26,974)        (11,581)
                                                                              --------      ----------
                                                                               440,645         443,297
                                                                              --------      ----------
OTHER ASSETS
Pipeline linefill                                                               34,312          17,633
Other, net                                                                      12,940          23,107
                                                                              --------      ----------
                                                                              $885,801      $1,223,037
                                                                              ========      ==========
                        LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES
Accounts payable and other current liabilities                                $328,542      $  485,400
Due to affiliates                                                               20,951          42,692
Short-term debt and current portion of long-term debt                            1,300         109,369
                                                                              --------      ----------
Total current liabilities                                                      350,793         637,461

LONG-TERM LIABILITIES
Bank debt                                                                      320,000         259,450
Subordinated note payable - general partner                                          -         114,000
Other long-term liabilities and deferred credits                                 1,009          19,153
                                                                              --------      ----------
Total liabilities                                                              671,802       1,030,064
                                                                              --------      ----------
COMMITMENTS AND CONTINGENCIES (NOTE 15)

PARTNERS' CAPITAL
Common unitholders (23,049,239 units outstanding)                              217,073         208,359
Class B Common unitholders (1,307,190 units outstanding)                        21,042          20,548
Subordinated unitholders (10,029,619 units outstanding)                        (27,316)        (35,621)
General partner                                                                  3,200            (313)
                                                                              --------      ----------
                                                                               213,999         192,973
                                                                              --------      ----------
                                                                              $885,801      $1,223,037
                                                                              ========      ==========

         See notes to consolidated and combined financial statements.

                                      F-4

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
                     (in thousands, except per unit data)

                                                                                                   PREDECESSOR
                                                                                                  -------------
                                                                                    NOVEMBER 23,    JANUARY 1,
                                                        YEAR ENDED DECEMBER 31,       1998 TO        1998 TO
                                                     ---------------------------    DECEMBER 31,   NOVEMBER 22,
                                                        2000            1999            1998          1998
                                                     ----------      -----------      --------      ----------
                                                                                         
REVENUES                                             $6,641,187      $10,910,423      $398,918      $3,118,353

COST OF SALES AND OPERATIONS                          6,506,504       10,800,109       391,419       3,087,372
UNAUTHORIZED TRADING LOSSES
AND RELATED EXPENSES (NOTE 3)                             6,963          166,440         2,400           4,700
                                                     ----------      -----------      --------      ----------
Gross Margin                                            127,720          (56,126)        5,099          26,281
                                                     ----------      -----------      --------      ----------
EXPENSES
General and administrative                               40,821           23,211           771           4,526
Depreciation and amortization                            24,523           17,344         1,192           4,179
Restructuring expense                                         -            1,410             -               -
                                                     ----------      -----------      --------      ----------
Total expenses                                           65,344           41,965         1,963           8,705
                                                     ----------      -----------      --------      ----------
Operating income (loss)                                  62,376          (98,091)        3,136          17,576

Interest expense                                        (28,691)         (21,139)       (1,371)        (11,260)
Gain on sale of assets (Note 5)                          48,188           16,457             -               -
Interest and other income                                10,776              958            12             572
                                                     ----------      -----------      --------      ----------
Net income (loss) before provision in lieu
of income taxes and extraordinary item                   92,649         (101,815)        1,777           6,888
Provision in lieu of income taxes                             -                -             -           2,631
                                                     ----------      -----------      --------      ----------
Net income (loss) before extraordinary item              92,649         (101,815)        1,777           4,257
Extraordinary item (Note 9)                             (15,147)          (1,545)            -               -
                                                     ----------      -----------      --------      ----------
NET INCOME (LOSS)                                    $   77,502      $  (103,360)     $  1,777      $    4,257
                                                     ==========      ===========      ========      ==========
NET INCOME (LOSS) - LIMITED PARTNERS                 $   75,754      $  (101,517)     $  1,741      $    4,172
                                                     ==========      ===========      ========      ==========
NET INCOME (LOSS) - GENERAL PARTNER                  $    1,748      $    (1,843)     $     36      $       85
                                                     ==========      ===========      ========      ==========
BASIC AND DILUTED INCOME (LOSS)
PER LIMITED PARTNER UNIT
Net income (loss) before extraordinary item               $2.64           $(3.16)        $0.06           $0.25
Extraordinary item                                        (0.44)           (0.05)            -               -
                                                     ----------      -----------      --------      ----------
Net income (loss)                                         $2.20           $(3.21)        $0.06           $0.25
                                                     ==========      ===========      ========      ==========
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING                                     34,386           31,633        30,089          17,004
                                                     ==========      ===========      ========      ==========

         See notes to consolidated and combined financial statements.

                                      F-5

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
              CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
                                (in thousands)

                                                                                                            PREDECESSOR
                                                                                                           ------------
                                                                                              NOVEMBER 23,   JANUARY 1,
                                                                  YEAR ENDED DECEMBER 31,        1998 TO      1998 TO
                                                               ----------------------------   DECEMBER 31,  NOVEMBER 22,
                                                                    2000            1999          1998         1998
                                                               ----------------------------    -----------   ----------
                                                                                                 
CASH FLOWS FROM OPERATING ACTIVITIES

Net income (loss)                                              $    77,502        $(103,360)   $   1,777   $   4,202
Items not affecting cash flows
  from operating activities:
    Depreciation and amortization                                   24,523           17,344        1,192       4,179
    (Gain) loss on sale of assets (Note 5)                         (48,188)         (16,457)           -         117
    Change in payable in lieu of deferred taxes                          -                -            -       2,231
    Noncash compensation expense                                     3,089            1,013            -           -
    Allowance for doubtful accounts                                  5,000                -            -           -
    Other non cash items                                             4,574            1,047           45           -
Change in assets and liabilities, net of acquisition:
    Accounts receivable and other                                  120,497         (224,181)     (10,245)     37,498
    Inventory                                                      (11,954)          34,772      (14,805)     (3,336)
    Accounts payable and other current liabilities                (161,543)         164,783       36,675     (25,850)
    Pipeline linefill                                              (16,679)              (3)      (6,247)      2,343
    Other long-term liabilities and deferred credits                (8,591)          18,873            -           -
    Advances from (payments to) affiliates                         (21,741)          34,924       (1,174)          -
                                                               -----------        ---------    ---------   ---------
Net cash provided by (used in) operating activities                (33,511)         (71,245)       7,218      21,384
                                                               -----------        ---------    ---------   ---------
CASH FLOWS FROM INVESTING ACTIVITIES

Costs incurred in connection with
  acquisitions (Note 4)                                                  -         (176,918)           -    (394,026)
Additions to property and equipment                                (12,603)         (12,801)      (2,887)     (5,528)
Disposals of property and equipment                                    402              294            -           8
Additions to other assets                                             (657)             (68)        (202)        (65)
Proceeds from asset sales (Note 5)                                 223,859            3,400            -           -
                                                               -----------        ---------    ---------   ---------
Net cash provided by (used in) investing activities                211,001         (186,093)      (3,089)   (399,611)
                                                               -----------        ---------    ---------   ---------
CASH FLOWS FROM FINANCING ACTIVITIES

Advances from (payments to) affiliates                                   -                -            -       3,349
Proceeds from issuance of units                                          -           76,450      241,690           -
Distributions upon formation                                             -                -     (241,690)          -
Costs incurred in connection
  with financing arrangements                                       (6,748)         (17,243)           -      (9,938)
Cash balance at formation                                                -                -          224           -
Subordinated notes - general partner                              (114,000)         114,000            -           -
Proceeds from long-term debt                                     1,433,750          403,721            -     331,300
Proceeds from short-term debt                                       51,300          131,119        1,150      30,600
Principal payments of long-term debt                            (1,423,850)        (268,621)           -     (39,300)
Principal payments of short-term debt                             (108,719)         (82,150)           -     (40,000)
Capital contribution from Parent                                         -                -            -     113,700
Dividend to Parent                                                       -                -            -      (3,557)
Distributions to unitholders                                       (59,565)         (51,673)           -           -
                                                               -----------        ---------    ---------   ----------
Net cash provided by (used in) financing activities               (227,832)         305,603        1,374     386,154
                                                               -----------        ---------    ---------   ---------
Net increase (decrease) in cash and cash equivalents               (50,342)          48,265        5,503       7,927
Cash and cash equivalents, beginning of period                      53,768            5,503            -           2
                                                               -----------        ---------    ---------   ---------
Cash and cash equivalents, end of period                       $     3,426        $  53,768    $   5,503   $   7,929
                                                               ===========        =========    =========   =========

         See notes to consolidated and combined financial statements.

                                      F-6

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
    FOR THE PERIOD FROM INCEPTION (NOVEMBER 23, 1998) TO DECEMBER 31, 1998
                AND THE YEARS ENDED DECEMBER 31, 1999 AND 2000
                                (in thousands)

                                                                                                                          Total
                                                              CLASS B                                     GENERAL        PARTNERS'
                                     COMMON  UNITS          COMMON UNITS        SUBORDINATED UNITS        PARTNER         CAPITAL
                                  --------------------    -----------------    ---------------------    -----------     -----------
                                    UNITS      AMOUNT      UNITS     AMOUNT      UNITS       AMOUNT        AMOUNT          AMOUNT
                                  --------   ---------    --------  --------   --------     ---------    ----------     -----------
                                                                                                   
Issuance of units to public         13,085     $241,690         -    $     -         -      $       -       $     -       $ 241,690

Contribution of assets and
  debt assumed                       6,974      106,392         -          -    10,030        153,005         9,369         268,766

Distribution at time
  of formation                           -      (95,675)        -          -         -       (137,590)       (8,425)       (241,690)

Net income for the period
  from November 23, 1998
  to December 31, 1998                   -        1,161         -          -         -            580            36           1,777
                                    ------     --------     ------   -------    ------      ---------       -------       ---------
Balance at
  December 31, 1998                 20,059      253,568         -          -    10,030         15,995           980         270,543

Issuance of Class B
  Common Units                           -            -     1,307     25,000         -              -           252          25,252

Noncash compensation expense             -            -         -          -         -              -         1,013           1,013

Issuance of units to public          2,990       50,654         -          -         -              -           544          51,198

Distributions                            -      (33,265)        -     (1,234)        -        (15,915)       (1,259)        (51,673)

Net loss                                 -      (62,598)        -     (3,218)        -        (35,701)       (1,843)       (103,360)
                                    ------     --------     ------   -------    ------      ---------       -------       ---------
Balance at December 31, 1999        23,049      208,359     1,307     20,548    10,030        (35,621)         (313)        192,973

Noncash compensation expense             -            -         -          -         -              -         3,089           3,089

Distributions                            -      (42,066)        -     (2,384)        -        (13,791)       (1,324)        (59,565)

Net income                               -       50,780         -      2,878         -         22,096         1,748          77,502
                                    ------     --------     ------   -------    ------      ---------       -------       ---------
Balance at December 31, 2000        23,049     $217,073     1,307    $21,042    10,030      $ (27,316)      $ 3,200       $ 213,999
                                    ======     ========     ======   =======    ======      =========       =======       =========

         See notes to consolidated and combined financial statements.

                                      F-7

              PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 1 -- Organization and Basis of Presentation

 Organization

  We are a Delaware limited partnership (the "Partnership") that was formed in
September of 1998 to acquire and operate the midstream crude oil business and
assets of Plains Resources Inc. ("Plains Resources") and its wholly owned
subsidiaries. On November 23, 1998, we completed our initial public offering and
the transactions whereby we became the successor to the business of the
midstream subsidiaries of Plains Resources, also referred to as our predecessor
or the Plains Midstream Subsidiaries. Our operations are conducted through
Plains Marketing, L.P. and All American Pipeline, L.P. Our general partner,
Plains All American Inc., is a wholly owned subsidiary of Plains Resources. We
are engaged in interstate and intrastate marketing, transportation and
terminalling of crude oil. Terminals are facilities where crude oil is
transferred to or from storage or a transportation system, such as trucks or
another pipeline. The operation of these facilities is called "terminalling".
Our operations are conducted primarily in California, Texas, Oklahoma,
Louisiana, Illinois and the Gulf of Mexico.

 Formation and Offering

  On November 23, 1998, we completed an initial public offering of 13,085,000
common units at $20.00 per unit, representing limited partner interests and
received net proceeds of approximately $244.7 million. Concurrently with the
closing of the initial public offering, certain of the Plains Midstream
subsidiaries were merged into Plains Resources, which sold the assets of these
subsidiaries to us in exchange for $64.1 million and the assumption of $11.0
million of related indebtedness. At the same time, our general partner conveyed
all of its interest in the All American Pipeline and the SJV Gathering System to
us in exchange for:

  .  6,974,239 common units, 10,029,619 subordinated units and an aggregate 2%
     general partner interest;
  .  the right to receive incentive distributions as defined in the partnership
     agreement; and
  .  our assumption of $175.0 million of indebtedness incurred by our general
     partner in connection with the acquisition of the All American Pipeline and
     the SJV Gathering System.

  In addition to the $64.1 million discussed above, we distributed approximately
$177.6 million of the offering proceeds to our general partner and used
approximately $3.0 million of the remaining proceeds to pay expenses incurred in
connection with the initial public offering.

 Basis of Consolidation and Presentation

  The accompanying financial statements and related notes present our
consolidated financial position as of December 31, 2000 and 1999, and the
results of our operations, cash flows and changes in partners' capital for the
years ended December 31, 2000 and 1999 and the period from inception (November
23, 1998) to December 31, 1998, and the results of operations and cash flows of
our predecessor for the period from January 1, 1998 to November 22, 1998. All
significant intercompany transactions have been eliminated. Certain
reclassifications have been made to prior period amounts to conform with current
period presentation.

NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Use of Estimates. The preparation of financial statements in conformity with
generally accepted accounting principles requires management 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 made by management incude (1)
depreciation and amortization, (2) allowance for doubtful accounts receivable
and (3) accrued liabilities. Although management believes these estimates are
reasonable, actual results could differ from these estimates.

  Revenue Recognition. Gathering and marketing revenues are accrued at the time
title to the product sold transfers to the purchaser, which occurs upon receipt
of the product by the purchaser, and purchases are accrued at the time title to
the product purchased transfers to us, which occurs upon our receipt of the
product. Terminalling and storage revenues are recognized at the time service is
performed. Revenues for the transportation of crude oil are recognized based
upon regulated and non-regulated tariff rates and the related transported
volumes.

                                      F-8

  Cost of Sales and Operations. Cost of sales and operations consists of the
cost of crude oil, transportation fees, field and pipeline operating expenses
and letter of credit expenses. Field and pipeline operating expenses consist
primarily of fuel and power costs, telecommunications, labor costs for pipeline
field personnel, maintenance, utilities, insurance and property taxes.

  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. At December 31, 2000 and 1999, the majority
of cash and cash equivalents is concentrated in one institution and at times may
exceed federally insured limits. We periodically assess the financial condition
of the institution and believe that any possible credit risk is minimal.

  Accounts Receivable, Net. At December 31, 2000, our allowance for doubtful
accounts receivable totaled $5.0 million and is reflected in the consolidated
balance sheet as a reduction of certain accounts receivable which are included
in Other Assets. The allowance was established in 2000 by a $5.0 million charge
to general and administrative expense.

  Inventory. Inventory consists of crude oil in pipelines and in storage tanks
which is valued at the lower of cost or market, with cost determined using the
average cost method.

  Property and Equipment and Pipeline Linefill. Property and equipment is stated
at cost and consists of:

                                                            December 31,
                                                    ----------------------------
                                                         2000          1999
                                                    -------------  -------------
                                                          (in thousands)

   Crude oil pipelines                              $  359,826     $  351,460
   Crude oil pipeline facilities                        39,358         39,358
   Crude oil storage and terminal facilities            45,989         43,583
   Trucking equipment, injection stations and other     19,435         18,249
   Office property and equipment                         3,011          2,228
                                                    -------------  -------------
                                                       467,619        454,878
   Less accumulated depreciation and amortization      (26,974)       (11,581)
                                                    -------------  -------------
                                                    $  440,645     $  443,297
                                                    =============  =============

Depreciation is computed using the straight-line method over estimated useful
lives as follows:

  .  crude oil pipelines - 40 years;
  .  crude oil pipeline facilities - 25 years;
  .  crude oil terminal and storage facilities - 30 to 40 years;
  .  trucking equipment, injection stations and other - 5 to 10 years; and
  .  other property and equipment - 5 to 7 years.

  Acquisitions and improvements are capitalized; maintenance and repairs are
expensed as incurred. Net gains or losses on property and equipment disposed of
are included in interest and other income in the period in which the transaction
occurs.

  Pipeline linefill is recorded at cost and consists of crude oil linefill used
to pack a pipeline such that when an incremental barrel enters a pipeline it
forces a barrel out at another location. At December 31, 2000, we had
approximately 1.6 million barrels of crude oil used to maintain our minimum
operating linefill requirements. Proceeds from the sale and repurchase of
pipeline linefill are reflected as cash flows from operating activities in the
accompanying consolidated and combined statements of cash flows. Proceeds from
the sale of 5.2 million barrels of crude oil linefill in connection with the
segment of the All American Pipeline that was sold are included in investing
activities in the accompanying consolidated and combined statements of cash
flows (see Note 5).

  Impairment of Long-Lived Assets. Long-lived assets, including any related
goodwill, with recorded values that are not expected to be recovered through
future cash flows are written-down to estimated fair value. Fair value is
generally determined from estimated discounted future net cash flows.

                                      F-9

  Other Assets. Other assets consist of the following (in thousands):

                                            DECEMBER 31,
                                        --------------------
                                           2000         1999
                                        -------      -------
        Debt issue costs                $ 8,918      $24,776
        Long-term receivable, net         5,000            -
        Goodwill and other                  770        1,994
                                        -------      -------
                                         14,688       26,770
        Accumulated amortization         (1,748)      (3,663)
                                        -------      -------
                                        $12,940      $23,107
                                        =======      =======

  Costs incurred in connection with the issuance of long-term debt 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" method of amortization. Goodwill was recorded as the
amount of the purchase price in excess of the fair value of certain
transportation and crude oil gathering assets purchased by our predecessor and
is amortized using the straight-line method over a period of twenty years.

  Federal Income Taxes. No provision for income taxes related to our operations
is included in the accompanying consolidated financial statements, because as a
partnership we are not subject to federal or state income tax and the tax effect
of our activities accrues to the unitholders. Net earnings 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 his/her tax position, may differ from the accounting followed in
the consolidated financial statements. Accordingly, there could be significant
differences between each individual unitholder's tax bases and his/her 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 bases cannot be readily determined. Accordingly, management does
not believe that in our circumstances, the aggregate difference would be
meaningful information.

  Our predecessor is included in the consolidated federal income tax return of
Plains Resources. Income taxes are calculated as if our predecessor had filed a
return on a separate company basis utilizing a federal statutory rate of 35%.

  Hedging. We utilize various derivative instruments, for purposes other than
trading, to hedge our exposure to price fluctuations on crude in storage and
expected purchases, sales and transportation of crude oil. The derivative
instruments consist primarily of futures and option contracts traded on the New
York Mercantile Exchange and crude oil swap contracts entered into with
financial institutions. We also utilize interest rate swaps and collars to
manage the interest rate exposure on our long-term debt.

  These derivative instruments qualify for hedge accounting as they reduce the
price risk of the underlying hedged item and are designated as a hedge at
inception. Additionally, the derivatives result in financial impacts that are
inversely correlated to those of the items being hedged. This correlation,
generally in excess of 80%, (a measure of hedge effectiveness) is measured both
at the inception of the hedge and on an ongoing basis. If correlation ceases to
exist, we would discontinue hedge accounting and apply mark to market
accounting. Gains and losses on the termination of hedging instruments are
deferred and recognized in income as the impact of the hedged item is recorded.

  Unrealized changes in the market value of crude oil hedge contracts are not
generally recognized in our statement of operations or our predecessor's
statements of operations until the underlying hedged transaction occurs. The
financial impacts of crude oil hedge contracts are included in our and our
predecessor's statements of operations as a component of revenues. Such
financial impacts are offset by gains or losses realized in the physical market.
Cash flows from crude oil hedging activities are included in operating
activities in the accompanying statements of cash flows. Net deferred gains and
losses on futures contracts, including closed futures contracts, entered into to
hedge anticipated crude oil purchases and sales, are included in current assets
or current liabilities in the accompanying consolidated balance sheets. Deferred
gains or losses from inventory hedges are included as part of the inventory
costs and recognized when the related inventory is sold.

  Amounts paid or received from interest rate swaps and collars are charged or
credited to interest expense and matched with the cash flows and interest
expense of the debt being hedged, resulting in an adjustment to the effective
interest rate.

                                      F-10

  Net income per unit. Basic and diluted net income (loss) per unit is
determined by dividing net income (loss) after deducting the amount allocated to
the general partner interest, by the weighted average number of outstanding
common units and subordinated units. Partnership income (loss) is allocated
first according to cash distributions, and the remainder according to percentage
ownership in the partnership. For periods prior to November 23, 1998,
outstanding units are assumed to equal the common and subordinated units
received by our general partner in exchange for assets contributed to us.

  Unit Options. We have elected to follow Accounting Principles Board Opinion
No. 25, Accounting for Stock Issued to Employees ("APB 25") and related
interpretations in accounting for our employee unit options and awards. Under
APB 25, no compensation expense is recognized when the exercise price of options
equals the fair value (market price) of the underlying units on the date of
grant (see Note 14).

  Recent Accounting Pronouncements. We implemented Emerging Issues Task Force
("EITF") Issue No. 99-19, "Recording Revenue Gross as a Principal versus Net as
an Agent" in the fourth quarter of 2000. Crude oil buy/sell contracts and
exchanges whereby like volumes are purchased and sold were previously reported
net in cost of sales and operations. These transactions have been reclassified
to be reflected as gross revenues and cost of sales and operations in our
statements of operations for all periods presented with no effect on earnings.
The amounts by which revenues and cost of sales and operations have been
reclassified for the years ended December 31, 2000 and 1999 and the periods
November 23, 1998 to December 31, 1998 and January 1, 1998 to November 22, 1998
are $2.5 billion, $6.2 billion, $0.2 billion, and $2.1 billion, respectively.

  In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 was
subsequently amended (i) in June 1999 by SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133" ("SFAS 137"), which deferred the effective date of
SFAS 133 to fiscal years beginning after June 15, 2000; and (ii) in June 2000 by
SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedge
Activities," which amended certain provisions, inclusive of the definition of
the normal purchase and sale exclusion.  We have determined that our physical
purchase and sale agreements, which under SFAS 133 could be considered
derivatives, qualify for the normal purchase and sale exclusion.

  SFAS 133 requires that all derivative instruments be recorded on the balance
sheet at their fair value. Changes in the fair value of derivatives are recorded
each period in current earnings or other comprehensive income, depending on
whether a derivative is designated as part of a hedge transaction and, if so,
the type of hedge transaction. For fair value hedge transactions in which we are
hedging changes in the fair value of an asset, liability, or firm commitment,
changes in the fair value of the derivative instrument will generally be offset
in the income statement by changes in the fair value of the hedged item. For
cash flow hedge transactions, in which we are hedging the variability of cash
flows related to a variable-rate asset, liability, or a forecasted transaction,
changes in the fair value of the derivative instrument will be reported in other
comprehensive income, a component of partners' capital. The gains and losses on
the derivative instrument that are reported in other comprehensive income will
be reclassified as earnings in the periods in which earnings are affected by the
variability of the cash flows of the hedged item. The ineffective portion of all
hedges will be recognized in earnings in the current period.

  We adopted SFAS 133, as amended, effective January 1, 2001. Our implementation
procedures identified all instruments in place at the adoption date that are
subject to the requirements of SFAS 133. Upon adoption, we recorded a cumulative
effect charge of $8.3 million in accumulated other comprehensive income to
recognize at fair value all derivative instruments that are designated as cash
flow hedging instruments and a cumulative effect gain of $0.5 million to
earnings. Correspondingly, an asset of $2.8 million and a liability of $10.6
million have been established. Implementation issues continue to be addressed by
the FASB and any change to existing guidance might impact our implementation.
Adoption of this standard could increase volatility in earnings and partners'
capital through comprehensive income.

NOTE 3 -- UNAUTHORIZED TRADING LOSSES

  In November 1999, we discovered that a former employee had engaged in
unauthorized trading activity, resulting in losses of approximately $162.0
million ($174.0 million, including estimated associated costs and legal
expenses). 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 from March through November 1999.
Approximately $7.1 million of the unauthorized trading losses was recognized in
1998 and the remainder in 1999. In 2000, we recognized an additional $7.0
million charge for litigation related to the unauthorized trading losses (see
Note 15).

                                      F-11

NOTE 4 -- ACQUISITIONS

 Scurlock Acquisition

  On May 12, 1999, we completed the acquisition of Scurlock Permian LLC 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 Scurlock acquisition was provided through:

  .  borrowings of approximately $92.0 million under a previous bank facility;
  .  the sale to our general partner of 1.3 million of our Class B common units
     for a total cash consideration of $25.0 million, or $19.125 per unit, the
     price equal to the market value of our common units on May 12, 1999; and
  .  a $25.0 million draw under our existing revolving credit agreement.

  The assets, liabilities and results of operations of Scurlock are included in
our consolidated financial statements effective May 1, 1999. The Scurlock
acquisition has been accounted for using the purchase method of accounting and
the purchase price was allocated in accordance with Accounting Principles Board
Opinion No. 16, Business Combinations, ("APB 16") as follows (in thousands):

        Crude oil pipeline, gathering and terminal assets         $125,120
        Other property and equipment                                 1,546
        Pipeline linefill                                           16,057
        Other assets (debt issue costs)                              3,100
        Other long-term liabilities (environmental accrual)         (1,000)
        Net working capital items                                   (3,090)
                                                                  --------
        Cash paid                                                 $141,733
                                                                  ========

  The purchase accounting entries include a $1.0 million accrual for estimated
environmental remediation costs. Under the agreement for the sale of Scurlock by
Marathon Ashland Petroleum to Plains Scurlock, Marathon Ashland Petroleum has
agreed to indemnify and hold harmless Scurlock and Plains Scurlock for claims,
liabilities and losses resulting from any act or omission attributable to
Scurlock's business or properties occurring prior to the date of the closing of
such sale to the extent the aggregate amount of such losses exceed $1.0 million;
provided, however, that claims for such losses must individually exceed $25,000
and must be asserted by Scurlock against Marathon Ashland Petroleum on or before
May 15, 2003.

 West Texas Gathering System Acquisition

  On July 15, 1999, we completed the acquisition of a West Texas crude oil
pipeline and gathering system from Chevron Pipe Line Company for approximately
$36.0 million, including transaction costs. Our total acquisition cost was
approximately $38.9 million including costs to address certain issues identified
in the due diligence process. The principal assets acquired include
approximately 450 miles of crude oil transmission mainlines, approximately 400
miles of associated gathering and lateral lines and approximately 2.9 million
barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland,
Upton, Ward and Winkler Counties, Texas. Financing for the amounts paid at
closing was provided by a draw under a previous credit facility.

                                      F-12

 Pro Forma Results for the Scurlock and West Texas Gathering System Acquisitions

  The following unaudited pro forma data is presented to show pro forma
revenues, net income (loss) and basic and diluted net income (loss) per limited
partner unit as if the Scurlock and West Texas Gathering System acquisitions had
occurred on January 1, 1998 (in thousands):

                                                 YEAR        NOVEMBER 23,   JANUARY 1,
                                                ENDED          1998 TO       1998 TO
                                              DECEMBER 31,   DECEMBER 31,  NOVEMBER 22,
                                                 1999           1998           1998
                                             ------------    ------------  -----------
                                                                   
Revenues                                     $11,301,492      $501,578      $4,272,060
                                             ===========      ========      ==========

Net income (loss)                            $   (97,501)     $ (8,080)     $      936
                                             ===========      ========      ==========

Basic and diluted net income (loss)
per limited partner unit                     $     (3.02)     $  (0.25)     $     0.05
                                             ===========      ========      ==========

 All American Pipeline Acquisition

  On July 30, 1998, our predecessor acquired all of the outstanding capital
stock of the All American Pipeline Company, Celeron Gathering Corporation and
Celeron Trading & Transportation Company (collectively the "Celeron
Companies") from Wingfoot, a wholly owned subsidiary of the Goodyear Tire and
Rubber Company ("Goodyear"), for approximately $400.0 million, including
transaction costs. The principal assets of the entities acquired include the All
American Pipeline and the SJV Gathering System, as well as other assets related
to such operations. The acquisition was accounted for utilizing the purchase
method of accounting and the purchase price was allocated in accordance with APB
16 as follows (in thousands):

Crude oil pipeline, gathering and terminal assets                 $392,528
Other assets (debt issue costs)                                      6,138
Net working capital items (excluding cash received of $7,481)        1,498
                                                                  --------
Cash paid                                                         $400,164
                                                                  ========

Financing for the acquisition was provided through a $325.0 million, limited
recourse bank facility and an approximate $114.0 million capital contribution by
Plains All American Inc.

  We incurred a $1.4 million restructuring charge in 1999, primarily associated
with severance-related expenses of 24 employees who were terminated. As of
December 31, 1999, all severance costs were paid and the terminated employees
were not employed by us.

 Pro Forma Results for the All American Pipeline Acquisition

  The following unaudited pro forma data is presented to show pro forma
revenues, net income and basic and diluted net income per limited partner unit
as if the All American Pipeline acquisition had occurred on January 1, 1998 (in
thousands):

                                                    JANUARY 1,
                                                     1998 TO
                                                   NOVEMBER 22,
                                                      1998
                                                   ------------
       Revenues                                     $3,556,002
                                                    ==========
       Net income                                   $   14,448
                                                    ==========
       Basic and diluted net income
       per limited partner unit                     $     0.83
                                                    ==========

NOTE 5 -- ASSET DISPOSITIONS

  In March 2000, we sold to a unit of El Paso Corporation ("El Paso") for $129.0
million the segment of the All American Pipeline that extends from Emidio,
California to McCamey, Texas. 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 Goodyear in July 1998.
We realized net proceeds of approximately $124.0 million after the associated
transaction

                                      F-13

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. The cost of the pipeline segment is
included in assets held for sale on the consolidated balance sheet at December
31, 1999.

  We had suspended shipments of crude oil on this segment of the pipeline in
November 1999. At that time, we owned approximately 5.2 million barrels of crude
oil in the segment of the pipeline. We sold this crude oil from November 1999 to
February 2000 for net proceeds of approximately $100.0 million, which were used
for working capital purposes. We recognized gains of approximately $28.1 million
and $16.5 million in 2000 and 1999, respectively, in connection with the sale of
the linefill. The amount of crude oil linefill for sale at December 31, 1999 was
$37.9 million and is included in assets held for sale on the consolidated
balance sheet.

NOTE 6 --DEBT

Short-term debt and current portion of long-term debt consists of the following
(in thousands):

                                                                                     DECEMBER 31,
                                                                                  -----------------
                                                                                   2000       1999
                                                                                  ------     ------
                                                                                        
Plains Marketing, L.P. letter of credit facility and hedged inventory
  facility, bearing interest at a weighted average interest rate
  of 8.4% at December 31, 2000                                                    $1,300    $      -
Letter of credit and borrowing facility, bearing interest at weighted average
  interest rate of  8.7% at December 31, 1999                                          -      13,719
Secured term credit facility, bearing interest at a weighted average
  interest rate of 8.8% at December 31, 1999                                           -      45,000
                                                                                  ------    --------
                                                                                   1,300      58,719
Current portion of long-term debt                                                      -      50,650
                                                                                  ------    --------
                                                                                  $1,300    $109,369
                                                                                  ======    ========

  Long-term debt consists of the following (in thousands):

                                                                                      DECEMBER 31,
                                                                                  --------------------
                                                                                    2000        1999
                                                                                  --------    --------
                                                                                          
Plains Marketing, L.P. revolving credit facility, bearing interest at
  a weighted average interest rate of 9.2% at December 31, 2000                   $320,000    $      -
All American Pipeline, L.P. bank credit agreement, bearing interest at
  a weighted average interest rate of 8.3% at December 31, 1999                          -     225,000
Plains Scurlock bank credit agreement, bearing interest at
  a weighted average interest rate of 9.1% at December 31, 1999                          -      85,100
Subordinated note payable - general partner, bearing interest at
  a weighted average interest rate of 8.7% at December 31, 1999                          -     114,000
                                                                                  --------    --------
                                                                                   320,000     424,100
Less current maturities                                                                  -     (50,650)
                                                                                  --------    --------
                                                                                  $320,000    $373,450
                                                                                  ========    ========

  On May 8, 2000, we entered into new bank credit agreements. The borrower under
the new facilities is Plains Marketing, L.P. We are a guarantor of the
obligations under the credit facilities. The obligations are also guaranteed by
the subsidiaries of Plains Marketing, L.P. We entered into the credit agreements
in order to:

  .  refinance the existing bank debt of Plains Marketing, L.P. and Plains
     Scurlock Permian, L.P. in conjunction with the merger of Plains Scurlock
     Permian, L.P. into All American Pipeline, L.P.;
  .  refinance existing bank debt of All American Pipeline, L.P.;
  .  repay up to $114.0 million plus accrued interest of subordinated debt to
     our general partner, and
  .  provide additional flexibility for working capital, capital expenditures,
     and for other general corporate purposes.

                                      F-14

  At December 31, 2000, our bank credit agreements consist of:

  .  a $400.0 million senior secured revolving credit facility. The revolving
     credit facility is secured by substantially all of our assets and matures
     in April 2004. No principal is scheduled for payment prior to maturity. The
     revolving credit facility bears interest at our option at either the base
     rate, as defined, plus an applicable margin, or LIBOR plus an applicable
     margin. We incur a commitment fee of 0.25% to 0.5% on the unused portion of
     the revolving credit facility.
  .  a $300.0 million senior secured letter of credit and borrowing facility,
     the purpose of which is to provide standby letters of credit to support the
     purchase and exchange of crude oil for resale and borrowings to finance
     crude oil inventory that has been hedged against future price risk. The
     letter of credit facility is secured by substantially all of our assets and
     has a sublimit for cash borrowings of $100.0 million to purchase crude oil
     that has been hedged against future price risk. The letter of credit
     facility expires in April 2003. Aggregate availability under the letter of
     credit facility for direct borrowings and letters of credit is limited to a
     borrowing base that is determined monthly based on certain of our current
     assets and current liabilities (primarily inventory and accounts receivable
     and accounts payable related to the purchase and sale of crude oil). At
     December 31, 2000, approximately $59.7 million in letters of credit were
     outstanding under the letter of credit and borrowing facility.

  Our bank credit agreements 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;
  .  grant liens;
  .  sell assets;
  .  make investments;
  .  engage in transactions with affiliates;
  .  enter into prohibited contracts; and
  .  enter into a merger or consolidation.

  Our bank credit agreements treat a change of control as an event of default
and also requires us to maintain:

  .  a current ratio (as defined) of 1.0 to 1.0;
  .  a debt coverage ratio that is not greater that 4.0 to 1.0 for the period
     from March 31, 2000 to March 31, 2002 and subsequently 3.75 to 1.0;
  .  an interest coverage ratio that is not less than 2.75 to 1.0; and
  .  a debt to capital ratio of not greater than 0.65 to 1.0.

  A default under our bank credit agreements would permit the lenders to
accelerate the maturity of the outstanding debt and to foreclose on the assets
securing the credit facilities. As long as we are in compliance with our bank
credit agreements, they do not restrict our ability to make distributions of
"available cash" as defined in our partnership agreement. We are currently in
compliance with the covenants contained in our credit agreements. At December
31, 2000, we could have borrowed up to $386.4 million available under our
secured revolving credit facility.

  In February 2001, our bank credit agreements were amended. The amount
available under the senior secured revolving credit facility was increased to
$500.0 million and the maturity date was extended to April 2005. The amount
available under the senior secured letter of credit and borrowing facility was
reduced to $200.0 million and the expiration date was extended to April 2004. In
addition, the banks agreed to an amendment which will allow us to borrow an
additional $130.0 million under the terms of the senior secured revolving credit
facility. We have an underwritten commitment, subject to conditions, for the
$130.0 million.

  In December 1999, our general partner loaned us $114.0 million that we used
for working capital requirements created by the 1999 unauthorized trading losses
(see Note 3). This loan was repaid in May 2000 with proceeds from our senior
secured revolving credit facility.

  On December 30, 1999, we entered into a $65.0 million senior secured term
credit facility to fund short-term working capital requirements resulting from
the unauthorized trading losses. The facility was secured by a portion of the
5.2 million barrels of linefill that was sold and receivables from certain sales
contracts applicable to the linefill. The facility had a maturity date of March
24, 2000 and was repaid with the proceeds from the sale of the linefill securing
the facility.

                                      F-15

  At December 31, 1999 we had a $225.0 million bank credit agreement that
included a $175.0 million term loan facility and a $50.0 million revolving
credit facility. As a result of the unauthorized trading losses discovered in
November 1999, the facility was in default of certain covenants, with those
defaults being subsequently waived and the facility amended in December 1999. At
December 31, 1999, we had $225.0 million outstanding under the terms of this
bank credit facility. In addition, at December 31, 1999, Plains Scurlock had a
bank credit agreement which consisted of a five-year $82.6 million term loan
facility and a three-year $35.0 million revolving credit facility. The revolving
credit facility could be used for borrowings or letters of credit to support
crude oil purchases. As of December 31, 1999, letters of credit of approximately
$29.5 million were outstanding under the revolver and borrowings of $82.6
million and $2.5 million were outstanding under the term loan and revolver,
respectively. Amounts outstanding under these credit agreements were repaid in
May 2000 with proceeds from our senior secured revolving credit facility.

 Maturities

  The aggregate amount of maturities of all long-term indebtedness at December
31, 2000 for the next five years is: 2004 - $320.0. After the February 2001
amendments to the revolving credit facility, the maturities were: 2005 - $320.0.

NOTE 7 -- PARTNERSHIP CAPITAL AND DISTRIBUTIONS

  Partner's capital consists of 24,356,429 common units, including 1,307,190
Class B common units, representing a 69.4% effective aggregate ownership
interest in the partnership and its subsidiaries, (a subsidiary of our general
partner owns 6,791,816 of such common units), 10,029,619 Subordinated units
owned by a subsidiary of our general partner representing a 28.6% effective
aggregate ownership interest in the partnership and its subsidiaries limited
partner interest and a 2% general partner interest. In the aggregate, our
general partner's interests represent an effective 54.0% ownership of our equity
at December 31, 2000.

  All of the subordinated units and 20,059,239 of the common units were issued
in connection with our November 1998 initial public offering. In October 1999,
we completed a public offering of an additional 2,990,000 common units
representing limited partner interests at $18.00 per unit. Net proceeds,
including our general partners' contribution, from the offering were
approximately $51.3 million after deducting underwriters' discounts and
commissions and offering expenses of approximately $3.1 million. These proceeds
were used to reduce outstanding debt. The Class B common units were issued in
May 1999 to our general partner at $19.125 per unit for total proceeds of $25.0
million in connection with the Scurlock acquisition.

  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. Distributions of available cash to holders of subordinated units
are subject to the prior rights of holders of common units to receive the
minimum quarterly distribution ("MQD") for each quarter during the subordination
period (which will not end earlier than December 31, 2003) and to receive any
arrearages in the distribution of the MQD on the common units for the prior
quarters during the subordination period. There were no arrearages on common
units at December 31, 2000. The MQD is $0.45 per unit ($1.80 per unit on an
annual basis). Upon expiration of the subordination period, all subordinated
units will be converted on a one-for-one basis into common units and will
participate pro rata with all other common units in future distributions of
available cash. Under certain circumstances, up to 50% of the subordinated units
may convert into common units prior to the expiration of the subordination
period. Common units will not accrue arrearages with respect to distributions
for any quarter after the subordination period and subordinated units will not
accrue any arrearages with respect to distributions for any quarter.

  If quarterly distributions of available cash exceed the MQD or the Target
Distribution Levels (as defined), our general partner will receive distributions
which are generally equal to 15%, then 25% and then 50% of the distributions of
available cash that exceed the MQD or Target Distribution Level. The Target
Distribution Levels are based on the amounts of available cash from our
Operating Surplus (as defined) distributed with respect to a given quarter that
exceed distributions made with respect to the MQD and common unit arrearages, if
any. Cash distributions for the second, third and fourth quarters of 2000 were
$0.4625 per unit on our outstanding common units, Class B units and subordinated
units, representing an increase of $0.0125 per unit over the MQD. Cash
distributions for the second and third quarters of 1999 were $0.4625 per unit
and $0.48125 per unit, respectively, on our outstanding common units, Class B
units and subordinated units, representing an increase of $0.0125 per unit and
$0.03125 per unit, respectively, over the MQD.

  The Class B common units are initially pari passu with common units with
respect to distributions, 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

                                      F-16

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 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.

NOTE 8 -- FINANCIAL INSTRUMENTS

 Derivatives

  We utilize derivative financial instruments to hedge our exposure to price
volatility on crude oil and do not use such instruments for speculative trading
purposes. These arrangements expose us to credit risk (as to counterparties) and
to risk of adverse price movements in certain cases where our purchases are less
than expected. In the event of non-performance of a counterparty, we might be
forced to acquire alternative hedging arrangements or be required to honor the
underlying commitment at then-current market prices. In order to minimize credit
risk relating to the non-performance of a counterparty, we enter into such
contracts with counterparties that are considered investment grade, periodically
review the financial condition of such counterparties and continually monitor
the effectiveness of derivative financial instruments in achieving our
objectives. In view of our criteria for selecting counterparties, our process
for monitoring the financial strength of these counterparties and our experience
to date in successfully completing these transactions, we believe that the risk
of incurring significant financial statement loss due to the non-performance of
counterparties to these transactions is minimal.

  At December 31, 2000, our hedging activities included crude oil futures
contracts maturing in 2000 through 2002, covering approximately 3.2 million
barrels of crude oil. Since such contracts are designated as hedges and
correlate to price movements of crude oil, any gains or losses resulting from
market changes will be largely offset by losses or gains on our hedged inventory
or anticipated purchases of crude oil. Such contracts resulted in a reduction in
revenues of $15.1 million and $17.8 million for the years ended December 31,
2000 and 1999, respectively. The unrealized loss with respect to such
instruments at December 31, 2000 and 1999 was $7.8 million and $9.8 million,
respectively.

  Interest rate swaps and collars are used to hedge underlying debt obligations.
These instruments hedge 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. At December 31, 2000, we had
interest rate swap and collar arrangements for an aggregate notional principal
amount of $215.0 million. The adjustment to interest expense resulting from
interest rate swaps for the years ended December 31, 2000 and 1999 was a $0.1
million gain and a $0.1 million loss. These instruments are based on LIBOR
margins and provide for a floor of 5% and a ceiling of 6.5% with an expiration
date of February 2001 for $90.0 million notional principal amount and a floor of
6% and a ceiling of 8% with an expiration date of August 2002 for $125.0 million
notional principal amount.

 Fair Value of Financial Instruments

  The carrying values of items comprising current assets and current liabilities
approximate fair value due to the short-term maturities of these instruments.
The carrying value of bank debt approximates fair value as interest rates are
variable, based on prevailing market rates. Crude oil futures contracts permit
settlement by delivery of the crude oil and, therefore, are not financial
instruments, as defined. The fair value of crude oil swaps and option contracts
and interest rate swap and collar agreements are based on current termination
values or quoted market prices of comparable contracts.

  The carrying amounts and fair values of our financial instruments are as
follows (in thousands):

                                                                                  DECEMBER 31,
                                                            -----------------------------------------------------
                                                                         2000                     1999
                                                            ----------------------------  -----------------------
                                                                 CARRYING        FAIR        CARRYING       FAIR
                                                                  AMOUNT         VALUE        AMOUNT       VALUE
                                                            ---------------   ----------   -----------  ---------

Unrealized loss on crude oil swaps and option contracts            $   -          $   -           -       $(569)
Unrealized gain (loss) on interest rate swaps and collars              -           (561)          -         388

NOTE 9 -- EARLY EXTINGUISHMENT OF DEBT

  During 2000, we recognized extraordinary losses, consisting primarily of
unamortized debt issue costs, totaling $15.1 million related to the permanent
reduction of the All American Pipeline, L.P. term loan facility and the
refinancing of our

                                      F-17

credit facilities. In addition, interest and other income for the year ended
December 31, 2000, includes $9.7 million of previously deferred gains from
terminated interest rate swaps as a result of debt extinguishment (see Notes 3
and 6). The extraordinary loss of $1.5 million in 1999 relates to the write-off
of certain debt issue costs and penalties associated with the prepayment of
debt.

NOTE 10 -- INCOME TAXES

  As discussed in Note 2, our predecessor's results are included in Plains
Resources' combined federal income tax return. The amounts presented below were
calculated as if our predecessor filed a separate tax return.

  Provision in lieu of income taxes of our predecessor consists of the following
components (in thousands):

                                              JANUARY 1,
                                               1998 TO
                                             NOVEMBER 22,
                                                1998
                                             ------------
                        Federal
                          Current              $  455
                          Deferred              1,900
                        State
                          Current                   -
                          Deferred                276
                                               ------
                        Total                  $2,631
                                               ======

  A reconciliation of the provision in lieu of income taxes to the federal
statutory tax rate of 35% is as follows (in thousands):

                                                    JANUARY 1,
                                                      1998 TO
                                                    NOVEMBER 22,
                                                       1998
                                                   -------------
        Provision at the statutory rate               $2,410
        State income tax, net of
          benefit for federal deduction                  181
        Permanent differences                             40
                                                      ------
        Total                                         $2,631
                                                      ======

NOTE 11 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

  In connection with our formation, certain investing and financial activities
occurred. Effective November 23, 1998, substantially all of the assets and
liabilities of our predecessor were conveyed to us at historical cost. Net
assets assumed by the operating partnership are as follows (in thousands):

    Cash and cash equivalents                                   $    224
    Accounts receivable                                          109,311
    Inventory                                                     22,906
    Prepaid expenses and other current assets                      1,059
    Property and equipment, net                                  375,948
    Pipeline linefill                                             48,264
    Intangible assets, net                                        11,001
                                                                --------
      Total assets conveyed                                      568,713
                                                                --------
    Accounts payable and other current liabilities               107,405
    Due to affiliates                                              8,942
    Bank debt                                                    183,600
                                                                --------
      Total liabilities assumed                                  299,947
                                                                --------
    Net assets assumed by the Partnership                       $268,766
                                                                ========

                                      F-18

  Interest paid totaled $25.9 million, $22.3 million, $0.1 million and $8.5
million for the years ended December 31, 2000 and 1999, the period from November
23, 1998 to December 31, 1998 and the period from January 1, 1998 through
November 23, 1998, respectively.

NOTE 12 -- MAJOR CUSTOMERS AND CONCENTRATION OF CREDIT RISK

  Customers accounting for 10% or more of revenues were as follows for the
periods indicated:

                                                                 PERCENTAGE
                                          -------------------------------------------------------
                                                                       NOVEMBER 23,   JANUARY 1,
                                          YEAR ENDED DECEMBER 31,        1998 TO       1998 TO
                                          -----------------------      DECEMBER 31,  NOVEMBER 22,
CUSTOMER                                   2000              1999         1998          1998
- -------------------------------------     ------            ------     -----------   ------------
                                                                            
Marathon Ashland Petroleum                  12%                 -           -             -
Sempra Energy Trading Corporation            -                 22%         20%           31%
Koch Oil Company                             -                 19%          -            19%
ExxonMobil                                   -                  -          11%            -

  All of the customers above pertain to our marketing, gathering, terminalling
and storage segment.

  Financial instruments which 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 generally require letters
of credit for receivables from customers that are not considered investment
grade, unless the credit risk can otherwise be reduced. We believe that the loss
of an individual customer would not have a material adverse effect.

NOTE 13 -- RELATED PARTY TRANSACTIONS

 Reimbursement of Expenses of Our General Partner and Its Affiliates

  We do not directly employ any persons to manage or operate our business. These
functions are provided by employees of our general partner and Plains Resources.
Our general partner does not receive a management fee or other compensation in
connection with its management of us. We reimburse our general partner and
Plains Resources for all direct and indirect costs of services provided,
including the costs of employee, officer and director compensation and benefits
properly allocable to us, and all other expenses necessary or appropriate to the
conduct of our business, and allocable to us. Our agreement provides that our
general partner will determine the expenses allocable to us in any reasonable
manner determined by our general partner in its sole discretion. Total costs
reimbursed to our general partner and Plains Resources by us were approximately
$63.8 million, $44.7 million and $0.5 million for the years ended December 31,
2000 and 1999 and for period from November 23, 1998 to December 31, 1998,
respectively. Such costs include, (1) allocated personnel costs (such as
salaries and employee benefits) of the personnel providing such services, (2)
rent on office space allocated to our general partner in Plains Resources'
offices in Houston, Texas (3) property and casualty insurance premiums and (4)
out-of-pocket expenses related to the provision of such services.

  Plains Resources allocated certain general and administrative expenses to the
Plains Midstream Subsidiaries during 1998. The types of indirect expenses
allocated to the Plains Midstream Subsidiaries during this period were office
rent, utilities, telephone services, data processing services, office supplies
and equipment maintenance. Direct expenses allocated by Plains Resources were
primarily salaries and benefits of employees engaged in the business activities
of the Plains Midstream Subsidiaries.

 Crude Oil Marketing Agreement

  We are the exclusive marketer/purchaser for all of Plains Resources' equity
crude oil production. The marketing agreement with Plains Resources provides
that we will purchase for resale at market prices all of Plains Resources' crude
oil production for which we charge a fee of $0.20 per barrel. For the years
ended December 31, 2000 and 1999 and the period from November 23, 1998 to
December 31, 1998, we paid Plains Resources approximately $244.9 million, $131.5
million and $4.1 million, respectively, for the purchase of crude oil under the
agreement, including the royalty share of production, and recognized profits of
approximately $1.7 million, $1.5 million and $0.1 million from the marketing fee
for the same periods, respectively. Prior to the marketing agreement, our
predecessor marketed crude oil production of Plains Resources, its subsidiaries
and its royalty owners. Our predecessor paid approximately $83.4 million for the
purchase of these products for

                                      F-19

the period from January 1, 1998 to November 22, 1998. In management's opinion,
these purchases were made at prevailing market prices. Our predecessor did not
recognize a profit on the sale of the crude oil purchased from Plains Resources.

 Financing

  In May 2000, we repaid to our general partner $114.0 million of subordinated
debt (see Note 6). Interest expense related to the notes was $3.3 million and
$0.6 million for the years ended December 31, 2000 and 1999, respectively.

  To finance a portion of the purchase price of the Scurlock acquisition, we
sold to our general partner 1.3 million Class B common units at $19.125 per
unit, the market value of our common units on May 12, 1999 (see Note4).

  The balance of amounts due to affiliates at December 31, 2000 and 1999 was
$21.0 million and $42.7 million, respectively, and was related to the
transactions discussed above.

 Benefit Plan

  Plains Resources maintains a 401(k) defined contribution plan whereby they
match 100% of an employee's contribution (subject to certain limitations in the
plan), with matching contribution being made 50% in cash and 50% in common stock
(the number of shares for the stock match being based on the market value of the
common stock at the time the shares are granted). For the years ended December
31, 2000, 1999 and 1998, defined contribution plan expense was $1.0 million,
$0.7 million and $0.2 million, respectively.

NOTE 14 -- LONG-TERM INCENTIVE PLANS

  Our general partner has adopted the Plains All American Inc. 1998 Long-Term
Incentive Plan for employees and directors of our general partner and its
affiliates who perform services for us. The Long-Term Incentive Plan consists of
two components, a restricted unit plan and a unit option plan. The Long-Term
Incentive Plan currently permits the grant of restricted units and unit options
covering an aggregate of 975,000 common units. The plan is administered by the
Compensation Committee of our general partner's board of directors.

  Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the
grantee to receive a common unit upon the vesting of the phantom unit. As of
March 15, 2001, an aggregate of approximately 610,100 restricted units have been
granted to employees of our general partner. In addition, 15,000 restricted
units have been granted to non-employee directors of our general partner. The
Compensation Committee may, in the future, make additional grants under the plan
to employees and directors containing such terms as the Compensation Committee
shall determine. In general, restricted units granted to employees during the
subordination period will vest only upon, and in the same proportions as, the
conversion of the subordinated units to common units. Grants made to non-
employee directors of our general partner are eligible to vest prior to
termination of the subordination period.

  If a grantee terminates employment or membership on the board for any reason,
the grantee's restricted 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, common units already owned by our general partner,
common units acquired by our general partner directly from us or any other
person, or any combination of the foregoing. Our general partner will be
entitled to reimbursement by us for the cost incurred in acquiring common units.
If we issue new common units upon vesting of the restricted units, the total
number of common units outstanding will increase. Following the subordination
period, the Compensation Committee, in its discretion, may grant tandem
distribution equivalent rights with respect to restricted units.

  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.

  Unit Option Plan. The Unit Option 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 equal to the fair
market value of the units on the date of grant. Unit options granted during the
subordination period will become exercisable automatically upon, and in the same
proportions as, the conversion of the subordinated units to common units, unless
a later vesting date is provided.

                                      F-20

  Upon exercise of a unit option, our general partner will deliver common units
acquired by it in the open market, purchased directly from us or any other
person, or use 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 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.

  The unit option plan has been designed to furnish additional compensation to
employees and directors and to align their economic interests with those of the
common unitholders. Our general partner's board of directors in its discretion
may terminate the Long-Term Incentive Plan at any time with respect to any
common units for which a grant has not yet been made. Our general partner's
board of directors also has the right to alter or amend the Long-Term Incentive
Plan or any part of the plan from time to time, including 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.

  We apply APB 25 and related interpretations in accounting for unit option
plans. In accordance with APB 25, no compensation expense has been recognized
for the unit option plan. Since no options have been granted to date, there is
no pro forma effect of a fair value based method of accounting in accordance
with SFAS No. 123 "Accounting for Stock-Based Compensation" ("SFAS 123").

  Transaction Grant Agreements. In addition to the grants made under the
Restricted Unit Plan described above, our general partner, at no cost to us,
agreed to transfer approximately 400,000 of its affiliates' common units
(including distribution equivalent rights attributable to such units) to certain
key officers and employees of our general partner and its affiliates. Generally,
under these grants, the common units vest based on attaining a targeted
operating surplus for a given year. Approximately 75,000 and 6,000 of the common
units vest for 2001 and 2002, respectively, if the operating surplus generated
in each year equals or exceeds the amount necessary to pay the minimum quarterly
distributions on all outstanding common units and the related distribution on
our general partner interest. If a tranche of common units does not vest for a
particular year due to a common unit arrearage, such common units will vest at
the time the common unit arrearages for such year have been paid. In addition,
approximately 58,000 and 11,000 of the common units vest for 2001and 2002,
respectively, if the operating surplus generated in such year exceeds the amount
necessary to pay the minimum quarterly distributions on all outstanding common
units and subordinated units and the related distributions on our general
partner interest. Approximately 69,000 and 113,000 (excluding approximately
20,000 units withheld for payment of federal income taxes) of the units vested
for 1999 and 2000, respectively and approximately 47,000 common units remain
unvested as no distribution on the subordinated units was made for the fourth
quarter of 1999. Any common units remaining unvested shall vest upon, and in the
same proportion as, the conversion of subordinated units to common units.
Distribution equivalent rights are paid in cash at the time of the vesting of
the associated common units. Notwithstanding the foregoing, all common units
become vested if Plains All American Inc. is removed as our general partner
prior to January 1, 2002.

  We recognized noncash compensation expense of approximately $3.1 million and
$1.0 million for the years ended December 31, 2000 and 1999, respectively,
related to the transaction grants which vested for 2000 and 1999. These amounts
are included in general and administrative expense on the Consolidated
Statements of Operations. We reflected a capital contribution from our general
partner for like amounts. There were no transaction grants which vested for
1998.

NOTE 15 -- COMMITMENTS AND CONTINGENCIES

  We lease certain real property, equipment and operating facilities under
various operating 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 canceled at any time should they not be
required for operations. Future non-cancelable commitments related to these
items at December 31, 2000, are summarized below (in thousands):

                        2001             $ 6,420
                        2002               3,716
                        2003               3,727
                        2004               3,744
                        2005               3,764
                        Thereafter         2,797

                                      F-21

  Total lease expense incurred for 2000 and 1999 was $6.7 million and $8.9
million, respectively. Lease expense incurred for the period from November 23,
1998 to December 31, 1998 and from January 1, 1998 to November 22, 1998 was $0.2
million and $0.9 million, respectively.

  During 1997, the All American Pipeline experienced a leak in a segment of its
pipeline in California that resulted in an estimated 12,000 barrels of crude oil
being released into the soil. Immediate action was taken to repair the pipeline
leak, contain the spill and to recover the released crude oil. We have expended
approximately $400,000 to date in connection with this spill and do not expect
any additional expenditures to be material, although we can provide no
assurances in that regard.

  Prior to being acquired by our predecessor in 1996, the Ingleside Terminal
experienced releases of refined petroleum products into the soil and groundwater
underlying the site due to activities on the property. We are undertaking a
voluntary state-administered remediation of the contamination on the property to
determine the extent of the contamination. We have proposed extending the scope
of our study and are awaiting the state's response. We have spent approximately
$140,000 to date in investigating the contamination at this site. We do not
anticipate the total additional costs related to this site to exceed $250,000,
although no assurance can be given that the actual cost could not exceed such
estimate. In addition, a portion of any such costs may be reimbursed to us from
Plains Resources.

 Litigation

  Texas Securities Litigation. On November 29, 1999, a class action lawsuit was
filed in the United States District Court for the Southern District of Texas
entitled Di Giacomo v. Plains All American Pipeline, L.P., et al. The suit
alleged that Plains All American and certain of our general partner's officers
and directors violated federal securities laws, primarily in connection with
unauthorized trading by a former employee. An additional nineteen cases have
been filed in the Southern District of Texas, some of which name our general
partner and Plains Resources as additional defendants. All of the federal
securities claims are being consolidated into two actions. The first
consolidated action is that filed by purchasers of Plains Resources' common
stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al.
The second consolidated action is that filed by purchasers of our common units,
and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al.
Plaintiffs alleged that the defendants were liable for securities fraud
violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of
1934 and for  making false registration statements under Sections 11 and 15 of
the Securities Act of 1933.

  We and Plains Resources reached an agreement with representatives for the
plaintiffs for the settlement of all of the class actions, and in January 2001,
we deposited approximately $30.0 million under the terms of the settlement
agreement. The total cost of the settlement to us and Plains Resources,
including interest and expenses and after insurance reimbursements, was $14.9
million. Of that amount, $1.0 million was allocated to Plains Resources by
agreement between special independent committees of the board of directors of
our general partner and the board of directors of Plains Resources. All such
amounts were reflected in our financial statements at December 31, 2000. The
settlement is subject to a number of conditions, including final approval by the
court. A hearing is set for March 30, 2001. The settlement agreement does not
affect the Texas Derivative Litigation and Delaware Derivative Litigation
described below.

  Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits
were filed in the Delaware Chancery Court, New Castle County, entitled Susser v.
Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et
al. These suits, and three others which were filed in Delaware subsequently,
named our general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to Plains All American Pipeline, L.P. and its unitholders by failing
to monitor properly the activities of its employees. The court has consolidated
all of the cases under the caption In Re Plains All American Inc. Shareholders
Litigation, and has designated the complaint filed in Susser v. Plains All
American Inc. as the complaint in the consolidated action. A motion to dismiss
was filed on behalf of the defendants on August 11, 2000.

  The plaintiffs in the Delaware derivative litigation seek that the defendants

  .  account for all losses and damages allegedly sustained by Plains All
     American from the unauthorized trading losses;
  .  establish and maintain effective internal controls ensuring that our
     affiliates and persons responsible for our affairs do not engage in
     wrongful practices detrimental to Plains All American;
  .  pay for the plaintiffs' costs and expenses in the litigation, including
     reasonable attorneys' fees, accountants' fees and experts' fees; and
  .  provide the plaintiffs any additional relief as may be just and proper
     under the circumstances.

                                      F-22

  We have reached an agreement in principle with the plaintiffs, subject to
approval by the Delaware court, to settle the Delaware litigation for
approximately $1.1 million.

  Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed
in the United States District Court of the Southern District of Texas entitled
Fernandes v. Plains All American Inc., et al, naming our general partner, its
directors and certain of its officers as defendants. This lawsuit contains the
same claims and seeks the same relief as the Delaware derivative litigation,
described above. A motion to dismiss was filed on behalf of the defendants on
August 14, 2000.

  We intend to vigorously defend the claims made in the Texas derivative
litigation. We believe that Delaware court approval of the settlement of the
Delaware derivative litigation will effectively preclude prosecution of the
Texas derivative litigation. However, there can be no assurance that we will be
successful in our defense or that this lawsuit will not have a material adverse
effect on our financial position or results of operation.

  We, in the ordinary course of business, are a claimant and/or a defendant in
various other legal proceedings. Management does 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.

  We may experience future releases of crude oil into the environment from our
pipeline and storage operations, or discover releases that were previously
unidentified. While 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.

NOTE 16 -- QUARTERLY FINANCIAL DATA (UNAUDITED)

                                                FIRST           SECOND            THIRD            FOURTH
                                               QUARTER          QUARTER           QUARTER         QUARTER (1)           TOTAL
                                            -------------     ------------      -----------    ----------------       ---------
                                                                       (IN THOUSANDS, EXCEPT PER UNIT DATA)
                                                                                                           
2000
- ----
Revenues, as reclassified (2)                $2,002,507        $1,481,834        $1,555,863        $1,600,983        $ 6,641,187
Revenues, as previously reported                999,319           738,967           756,926                 -          2,495,212
Gross margin (3)                                 36,552            32,774            25,960            32,434            127,720
Operating income                                 17,788            20,164            10,700            13,724             62,376
Net income before extraordinary item             64,300            17,063             4,516             6,770             92,649
Extraordinary item                               (4,145)          (11,002)                -                 -            (15,147)
Net income                                       60,155             6,061             4,516             6,770             77,502
Net income per limited partner unit
  Before extraordinary item                        1.83              0.49              0.13              0.19               2.64
  Extraordinary item                              (0.12)            (0.32)                -                 -              (0.44)
  After extraordinary item                         1.71              0.17              0.13              0.19               2.20
Cash distributions per common unit (4)       $    0.450        $    0.463        $    0.463        $    0.463        $     1.839

1999
- ----
Revenues, as reclassified (2)                $1,128,839        $2,535,200        $3,000,282        $4,246,102        $10,910,423
Revenues, as previously reported                471,209           885,046         1,127,808         2,255,829          4,739,892
Gross margin (3)                                 (1,546)            4,985           (38,922)          (20,643)           (56,126)
Operating loss                                   (6,965)           (4,624)          (53,839)          (32,663)           (98,091)
Net loss before extraordinary item              (10,061)           (9,154)          (60,131)          (22,469)          (101,815)
Extraordinary item                                    -                 -                 -            (1,545)            (1,545)
Net loss                                        (10,061)           (9,154)          (60,131)          (24,014)          (103,360)
Net loss per limited partner unit
  Before extraordinary item                       (0.33)            (0.29)            (1.88)            (0.64)             (3.16)
  Extraordinary item                                  -                 -                 -             (0.05)             (0.05)
  After extraordinary item                        (0.33)            (0.29)            (1.88)            (0.69)             (3.21)
Cash distributions per common unit (4)       $    0.450        $    0.463        $    0.481        $    0.450        $     1.844

- ------------------------
(1)  For 2000, includes a $5.0 million charge to reserve for potentially
     uncollectible accounts receivable.
(2)  These amounts represent the reclassification from previously reported
     amounts due to the adoption of EITF 99-19 (see Note 2).
(3)  For the third and fourth quarters of 2000, includes the effects of the
     charge for litigation related to the unauthorized trading losses and the
     effects of the unauthorized trading losses for all quarters of 1999 (see
     Note 3).
(4)  Represents cash distributions declared and paid per common unit for the
     period indicated. Distributions are paid in the following calendar quarter.

                                      F-23

NOTE 17 -- OPERATING SEGMENTS

  Our operations consist of two operating segments: (1) Pipeline Operations -
engages in interstate and intrastate crude oil pipeline transportation and
certain related merchant activities; (2) Marketing, Gathering, Terminalling and
Storage Operations - engages in purchases and resales of crude oil at various
points along the distribution chain and the leasing of certain terminalling and
storage assets. Prior to the July 1998 acquisition of the All American Pipeline
and SJV Gathering System, our predecessor had only marketing, gathering,
terminalling and storage operations. We evaluate segment performance based on
gross margin, gross profit and income before provision in lieu of income taxes
and extraordinary items.

  The following table summarizes segment revenues, gross margin, gross profit
and income (loss) before provision in lieu of income taxes and extraordinary
items:

                                                                               MARKETING,
                                                                               GATHERING,
                                                                              TERMINALLING
 (IN THOUSANDS)                                                 PIPELINE      & STORAGE (a)       TOTAL (a)
- -----------------------------------------------------------------------------------------------------------
                                                                                         
 2000
 Revenues:
   External Customers                                         $505,712       $ 6,135,475        $ 6,641,187
   Intersegment  (b)                                            68,745                 -             68,745
   Other                                                         9,045             1,731             10,776
                                                              --------       -----------        -----------
     Total revenues of reportable segments                    $583,502       $ 6,137,206        $ 6,720,708
                                                              ========       ===========        ===========
 Segment gross margin (c)                                     $ 51,787       $    75,933        $   127,720
 Segment gross profit (d)                                       49,996            36,903             86,899
 Net income (loss) before extraordinary item                    94,461            (1,812)            92,649
 Interest expense                                                5,738            22,953             28,691
 Depreciation and amortization                                   7,030            17,493             24,523
 Capital expenditures                                            1,544            11,059             12,603
 Total assets                                                  324,751           561,050            885,801
- -----------------------------------------------------------------------------------------------------------
 1999
 Revenues:
   External Customers                                         $854,377       $10,056,046        $10,910,423
   Intersegment  (b)                                           131,445                 -            131,445
   Other                                                           195               763                958
                                                              --------       -----------        -----------
     Total revenues of reportable segments                    $986,017       $10,056,809        $11,042,826
                                                              ========       ===========        ===========
 Segment gross margin (c)                                     $ 58,001       $  (114,127)       $   (56,126)
 Segment gross profit (d)                                       55,384          (134,721)           (79,337)
 Net income (loss) before extraordinary item                    46,075          (147,890)          (101,815)
 Interest expense                                               13,572             7,567             21,139
 Depreciation and amortization                                  10,979             6,365             17,344
 Capital expenditures                                           69,375           119,911            189,286
 Total assets                                                  524,438           698,599          1,223,037
- -----------------------------------------------------------------------------------------------------------
 NOVEMBER 23, 1998 TO DECEMBER 31, 1998
 Revenues:
   External Customers                                         $ 54,089       $   344,829        $   398,918
   Intersegment  (b)                                             2,029               429              2,458
   Other                                                             -                12                 12
                                                              --------       -----------        -----------
      Total revenues of reportable segments                   $ 56,118       $   345,270        $   401,388
                                                              ========       ===========        ===========
 Segment gross margin (c)                                     $  3,546       $     1,553        $     5,099
 Segment gross profit (d)                                        3,329               999              4,328
 Net income                                                      1,035               742              1,777
 Interest expense                                                1,321                50              1,371
 Depreciation and amortization                                     973               219              1,192
 Capital expenditures                                              352             2,535              2,887
 Total assets                                                  471,864           135,322            607,186
- -----------------------------------------------------------------------------------------------------------

                                                                          Table continued on following page

                                      F-24

                                                                               MARKETING,
                                                                               GATHERING,
                                                                              TERMINALLING
 (IN THOUSANDS)                                                 PIPELINE      & STORAGE (a)       TOTAL (a)
- ---------------------------------------------------------------------------------------------------------
January 1, 1998 to November 22, 1998 (Predecessor)
                                                                                        
 Revenues:
 External Customers                                           $200,139       $2,918,214        $3,118,353
 Intersegment  (b)                                              21,166            2,391            23,557
 Other                                                             603              (31)              572
                                                              --------       ----------        ----------
 Total revenues of reportable segments                        $221,908       $2,920,574        $3,142,482
                                                              ========       ==========        ==========

 Segment gross margin (c)                                     $ 13,222       $   13,059        $   26,281
 Segment gross profit (d)                                       12,394            9,361            21,755
 Net income before provision in lieu of income taxes             2,152            4,736             6,888
 Interest expense                                                7,787            3,473            11,260
 Depreciation and amortization                                   3,058            1,121             4,179
 Provision in lieu of income taxes                                 822            1,809             2,631
 Capital expenditures                                          393,379            4,677           398,056
- ---------------------------------------------------------------------------------------------------------

a)  Revenues for the marketing, gathering, terminalling and storage segment
    include the effects of the adoption of EITF 99-19 (see Note 2). For the
    years ending December 31, 2000 and 1999 and the periods November 23, 1998 to
    December 31, 1998 and January 1, 1998 to November 22, 1998, revenues have
    been reclassified by $2.5 billion, $6.2 billion, $0.2 billion and $2.1
    billion, respectively.

b)  Intersegment sales were conducted on an arm's length basis.
c)  Gross margin is calculated as revenues less cost of sales and operations
    expenses.
d)  Gross profit is calculated as revenues less costs of sales and operations
    expenses and general and administrative expenses.

NOTE 18 -- SUBSEQUENT EVENTS

 Acquisitions

  Murphy Oil Company Ltd. Midstream Operations

  On March 1, 2001, we signed an agreement to purchase substantially all of the
crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil
Company Ltd. ("Murphy") for approximately $155.0 million in cash, plus an
additional cash payment, to be determined prior to closing in accordance with
the agreement, for excess inventory in the systems (estimated to be
approximately $5.0 million). The principal assets to be acquired include
approximately 450 miles of crude oil and condensate transmission mainlines and
associated gathering and lateral lines, and approximately 1.1 million barrels of
crude oil storage and terminalling capacity located primarily in Kerrobert,
Saskatchewan, approximately 200,000 barrels of linefill, as well as a currently
inactive 108-mile mainline system and 121 trailers used primarily for crude oil
transportation.

  Murphy has agreed to continue to transport production from fields currently
delivering crude oil to these pipeline systems, under a new long-term contract.
The current volume is approximately 11,000 barrels per day. The pipeline systems
transport approximately 200,000 barrels per day of light, medium and heavy
crudes, as well as condensate.

  Canadian Marketing Assets

  We have entered into a letter of intent to purchase the assets of a Canadian
marketing company. The expected purchase price is approximately $43.0 million,
of which approximately $18.0 million will be subject to certain performance
targets. The marketing company currently gathers approximately 75,000 barrels
per day of crude oil and markets approximately 26,000 barrels per day of natural
gas liquids. Tangible assets include a crude oil handling facility, a 100,000
barrel tank facility and working capital of approximately $8.5 million.

  Initial financing for the acquisitions will be provided via an expansion of
our existing revolving credit, letter of credit and inventory facility. The
expanded facility will initially be underwritten by Fleet Boston and will
consist of a $100.0 million five-year term loan and a $30.0 million revolving
credit facility that will expire in April 2005.

                                      F-25

                                                                   Exhibit 10.17

                                                                  Execution Copy
                      FIRST AMENDMENT TO CREDIT AGREEMENT
                          [Revolving Credit Facility]

     THIS FIRST AMENDMENT TO CREDIT AGREEMENT (this "Amendment") dated as of the
26th day of February, 2001, by and among PLAINS MARKETING, L.P. ("Borrower"),
ALL AMERICAN PIPELINE, L.P. ("All American") and PLAINS ALL AMERICAN PIPELINE,
L.P. ("Plains MLP"), as guarantors, FLEET NATIONAL BANK, as Administrative Agent
(in such capacity, "Administrative Agent"), and the Lenders party hereto.

                              W I T N E S S E T H:

     WHEREAS, Borrower, All American, Plains MLP, Administrative Agent and
Lenders entered into that certain Credit Agreement [Revolving Credit Facility]
dated as of May 8, 2000 (as amended, restated, or supplemented to the date
hereof, the "Original Agreement") for the purposes and consideration therein
expressed, pursuant to which Lenders became obligated to make and made loans to
Borrower as therein provided; and

     WHEREAS, Borrower, All American, Plains MLP, Administrative Agent, and
Lenders desire to amend the Original Agreement for the purposes described
herein;

     NOW, THEREFORE, in consideration of the premises and the mutual covenants
and agreements contained herein and in the Original Agreement, in consideration
of the loans which may hereafter be made by Lenders to Borrower, and for other
good and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto do hereby agree as follows:

                    ARTICLE I. -- Definitions and References

     (S) 1.1.  Terms Defined in the Original Agreement.  Unless the context
otherwise requires or unless otherwise expressly defined herein, the terms
defined in the Original Agreement shall have the same meanings whenever used in
this Amendment.

     (S) 1.2.  Other Defined Terms.  Unless the context otherwise requires, the
following terms when used in this Amendment shall have the meanings assigned to
them in this (S) 1.2.

          "Amendment" means this First Amendment to Credit Agreement.

          "Amendment Documents" means this Amendment, the Renewal Notes, and the
     Amendments to Security Documents as described in Section 3.1(c) hereof.

          "Credit Agreement" means the Original Agreement as amended hereby.

          "Original Notes" means the "Notes" referred to and defined as such in
     the Original Agreement.

                                                       Revolving Credit Facility

                                       1

          "Renewal Notes" means the renewal promissory notes of Borrower in the
     form attached hereto as Exhibit A, expressly renewing, extending and
     increasing the Original Notes.

                           ARTICLE II. -- Amendments

     (S) 2.1.  Definitions.  (a)  Applicable Leverage Level.  The table set
forth in the definition of "Applicable Leverage Level" set forth in Section 1.1
of the Original Agreement is hereby amended in its entirety to read as follows:

        Applicable
      Leverage Level                Leverage Ratio
     -----------------   ------------------------------------
     Level I             greater than or equal to 4.50 to 1.0

     Level II            greater than or equal to 4.25 to 1.0
                              but less than 4.50 to 1.0

     Level III           greater than or equal to 4.00 to 1.0
                              but less than 4.25 to 1.0

     Level IV            greater than or equal to 3.50 to 1.0
                              but less than 4.00 to 1.0

     Level V             greater than or equal to 3.00 to 1.0
                              but less than 3.50 to 1.0

     Level VI            greater than or equal to 2.25 to 1.0
                              but less than 3.00 to 1.0

     Level VII           greater than or equal to 1.75 to 1.0
                              but less than 2.25 to 1.0

     Level VIII                 less than 1.75 to 1.0

     (b) Base Rate Margin:  The table set forth in the definition of "Base
Rate Margin" set forth in Section 1.1 of the Original Agreement is hereby
amended in its entirety to read as follows:

                                                       Revolving Credit Facility

                                       2

 Applicable Leverage Level     Base Rate Margin
- -----------------------------------------------
Level I                                   1.500%
- -----------------------------------------------
Level II                                  1.250%
- -----------------------------------------------
Level III                                 1.125%
- -----------------------------------------------
Level IV                                  1.000%
- -----------------------------------------------
Level V                                   0.500%
- -----------------------------------------------
Level VI                                  0.250%
- -----------------------------------------------
Level VII or Level VIII                   0.000%
- -----------------------------------------------

     (c) Commitment.  The definition of "Commitment" set forth in Section 1.1 of
the Original Agreement is hereby amended in its entirety to read as follows:

          "Commitment" means, subject to the last sentence of Section 2.1,
     $471,666,666.67.  Each Lender's Commitment shall be the amount initially
     set forth on the Lender Schedule, as such Lender's Commitment may be
     reduced or increased from time to time pursuant to assignments by or to
     such Lender pursuant to Section 10.5(c), or increased from time to time
     pursuant to the last sentence of Section 2.1.

     (d) Commitment Fee Rate.  The table set forth in the definition of
"Commitment Fee Rate" set forth in Section 1.1 of the Original Agreement is
hereby amended in its entirety to read as follows:

     Applicable Leverage Level        Commitment Fee Rate
- ---------------------------------------------------------
Level I or Level II or Level III                    0.500%
 or Level IV or Level V
- ---------------------------------------------------------
Level VI or Level VII                               0.375%
- ---------------------------------------------------------
Level VIII                                          0.250%
- ---------------------------------------------------------

     (e) Consolidated EBITDA.  Clause (5) of the definition of "Consolidated
EBITDA" set forth in Section 1.1 of the Original Agreement is hereby renumbered
clause (6), and a new clause (5) is hereby added immediately before "minus"
preceding such clause (6), to read as follows:

     plus (5) settlement payments made in such period with respect to litigation
     arising out of the unauthorized trading activity by Borrower during the
     period of January 1, 1999 to November 20, 1999, not to exceed an aggregate
     amount of $6,963,000

                                                       Revolving Credit Facility

                                       3

     (f) Consolidated Funded Indebtedness.  The proviso at the end of the last
sentence of the definition of "Consolidated Funded Indebtedness" set forth in
Section 1.1 of the Original Agreement is hereby amended in its entirety to read
as follows:

     provided, however, that Consolidated Funded Indebtedness shall not include
     Indebtedness in respect of letters of credit, Cash and Carry Purchases, or
     margin deposits.

     (g) Letter of Credit Fee Rate.  The table set forth in the definition of
"Letter of Credit Fee Rate" set forth in Section 1.1 of the Original Agreement
is hereby amended in its entirety to read as follows:

 Applicable Leverage Level     LC Fee Rate
- ------------------------------------------
Level I                              3.000%
- ------------------------------------------
Level II                             2.750%
- ------------------------------------------
Level III                            2.625%
- ------------------------------------------
Level IV                             2.500%
- ------------------------------------------
Level V                              2.000%
- ------------------------------------------
Level VI                             1.750%
- ------------------------------------------
Level VII                            1.500%
- ------------------------------------------
Level VIII                           1.250%
- ------------------------------------------

     (h) LIBOR Rate Margin.  The table set forth in the definition of "LIBOR
Rate Margin" set forth in Section 1.1 of the Original Agreement is hereby
amended in its entirety to read as follows:

                                                       Revolving Credit Facility

                                       4

Applicable Leverage Level      LIBOR Rate Margin
- ------------------------------------------------
Level I                                    3.000%
- ------------------------------------------------
Level II                                   2.750%
- ------------------------------------------------
Level III                                  2.625%
- ------------------------------------------------
Level IV                                   2.500%
- ------------------------------------------------
Level V                                    2.000%
- ------------------------------------------------
Level VI                                   1.750%
- ------------------------------------------------
Level VII                                  1.500%
- ------------------------------------------------
Level VIII                                 1.250%
- ------------------------------------------------

     (i) Maturity Date.  The reference to "April 30, 2004" set forth in the
definition of "Maturity Date" set forth in Section 1.1 of the Original Agreement
is hereby amended to refer instead to "April 30, 2005".

     (j) Permitted Investments.  Clause (c) of the definition of "Permitted
Investments" set forth in Section 1.1 of the Original Agreement is hereby
amended in its entirety to read as follows:

     (c) Investments by Plains MLP or any of its Subsidiaries in:

          (I) any Wholly Owned Subsidiary of Plains MLP which is a Guarantor,
     other than any Canadian Subsidiary or

          (II) any Canadian Subsidiary, provided that (A) Borrower shall notify
     Administrative Agent and each Lender in the event the aggregate amount of
     such Investments in Canadian Subsidiaries shall exceed $100,000 and (B) the
     aggregate amount of such Investments in Canadian Subsidiaries shall not
     exceed (x) $100,000 in the aggregate prior to the earlier of the CanPet
     Acquisition Closing Date and Murphy Acquisition Closing Date, (y)
     $27,000,000 (exclusive of any Investment described in clause (z) below)
     with respect to the CanPet Acquisition, the proceeds of which shall be used
     to consummate the CanPet Acquisition, to fund contango transactions and for
     working capital purposes with respect to the CanPet Acquisition, and (z)
     $57,000,000 (exclusive of any Investment described in clause (y) above)
     with respect to the Murphy Acquisition, the proceeds of which shall be used
     to consummate the Murphy Acquisition, to fund contango transactions and for
     working capital purposes with respect to the Murphy Acquisition.

     The reference to "$5,000,000" set forth in clause (d) of such definition is
hereby amended to refer instead to "the Dollar Equivalent of $5,000,000".

                                                       Revolving Credit Facility

                                       5

     (k) Canadian Dollars, Canadian Subsidiaries and CanPet Acquisition.  The
following definitions of "Canadian Dollars", "Canadian Subsidiaries", "CanPet
Acquisition", "Canpet Acquisition Documents" and "Canpet Closing Date" are
hereby added to Section 1.1 of the Original Agreement immediately following the
definition of "Business Day", to read as follows:

          "Canadian Dollars" and "C$" means the lawful currency of Canada.

          "Canadian Subsidiaries" means each of PMC (Nova Scotia) Company, a
     Nova Scotia unlimited liability company, Plains Marketing Canada, L.P., an
     Alberta limited partnership, and each of their Subsidiaries, whether now
     owned or hereafter acquired.

          "CanPet Acquisition" means the acquisition by Borrower and Plains
     Marketing Canada, L.P. of all or substantially all of the assets of CanPet
     Energy Group (USA), Inc. and CanPet Energy Group Inc., respectively,
     pursuant to the CanPet Acquisition Documents.

          "CanPet Acquisition Documents" means the purchase and sale agreement,
     title transfer documents and all other agreements or instruments executed
     and delivered by Borrower, Plains Marketing Canada, L.P. or any Affiliate
     in connection therewith to consummate the CanPet Acquisition.

          "CanPet Acquisition Closing Date" means the date on which the CanPet
     Acquisition shall have been consummated and Borrower and Plains Marketing
     Canada, L.P. shall have taken good and defensible title to the assets
     subject thereof.

     (l) Dollars and Dollar Equivalent.  The following definitions of "Dollars"
and "Dollar Equivalent" are hereby added to Section 1.1 of the Original
Agreement immediately following the definition of "Disclosure Schedule", to read
as follows:

          "Dollars" and "$" means U.S. dollars except where otherwise specified.

          "Dollar Equivalent" of any amount of any currency at any date means
     (i) if such currency is Dollars, the amount of such currency, or (ii) if
     such currency is Canadian Dollars, the equivalent in Dollars of such amount
     of such currency based upon the rate of exchange for such conversion as
     quoted by the Bank of Canada at approximately 12:00 noon, Toronto time (or,
     if not so quoted, the spot rate of exchange quoted for wholesale
     transactions made by Administrative Agent) on the date on or as of which
     such amount is to be determined.

     (m) Murphy Acquisition.  The following definitions of "Murphy Acquisition",
"Murphy Acquisition Documents" and "Murphy Acquisition Closing Date" are hereby
added to Section 1.1 of the Original Agreement immediately following the
definition of "Moody's", to read as follows:

                                                       Revolving Credit Facility

                                       6

          "Murphy Acquisition" means the acquisition by Plains Marketing Canada,
     L.P. of certain assets from Murphy Oil Company Ltd. as previously disclosed
     by Borrower to Administrative Agent and Lenders pursuant to the Murphy
     Acquisition Documents.

          "Murphy Acquisition Documents" means the purchase and sale agreement,
     title transfer documents and all other agreements or instruments executed
     and delivered by Plains Marketing Canada, L.P. or any Affiliate in
     connection therewith to consummate the Murphy Acquisition.

          "Murphy Acquisition Closing Date" means the date on which the Murphy
     Acquisition shall have been consummated and Plains Marketing Canada, L.P.
     shall have taken good and defensible title to the assets subject thereof.

     (S) 2.2.  Amendment of Marketing Credit Agreement.  The second sentence of
Section 1.3 of the Original Agreement is hereby amended by adding the following
phrase at the end thereof:

     , as amended by the First Amendment to Credit Agreement [Letter of Credit
     and Hedged Inventory Facility] dated as of February 26, 2001 and as amended
     and restated as contemplated by and provided for in such First Amendment.

     (S) 2.2A.  Maximum Commitment.  Section 2.1 of the Original Agreement is
hereby amended by adding the following sentence at the end thereof:

     Borrower shall have the right, without the consent of the Lenders but with
     the prior approval of the Administrative Agent, not to be unreasonably
     withheld, to cause from time to time an increase in the Commitment by
     adding to this Agreement one or more additional Lenders or by allowing one
     or more Lenders to increase their respective Commitments; provided however
     (i) no Event of Default shall have occurred hereunder which is continuing,
     (ii) no such increase shall result in the aggregate Commitment hereunder to
     exceed $500,000,000, (iii) no Lender's Commitment shall be increased
     without such Lender's consent, and (iv) on the effective date of any such
     increase, there shall be no outstanding LIBOR Loans hereunder.

     (S) 2.3.  Notices and Environmental Matters.  The references to
"$1,000,000" set forth in Section 6.4(e), 6.12(b) and 6.12(c) of the Original
Agreement are hereby amended to refer instead to "the Dollar Equivalent of
$1,000,000".

     (S) 2.4.  Indebtedness under Marketing Credit Agreement and Issuance of
Additional Indebtedness.  The reference to "$350,000,000" set forth in Section
7.1(e) of the Original Agreement is hereby amended to refer instead to
"$300,000,000".

     Clause (g) of Section 7.1 of the Original Agreement is hereby redesignated
clause (h), and a new clause (g) is hereby added immediately before such clause
(h), to read as follows:

                                                       Revolving Credit Facility

                                       7

          (g) Indebtedness owing by Plains MLP or any other Restricted Person
     under its senior unsecured privately placed or public term Indebtedness
     (and any Indebtedness issued in exchange therefor), provided (1) such
     Indebtedness shall not permit optional redemption by the issuer or
     mandatory redemption by any holder thereof solely at the option of any such
     holder, nor any stated maturity, in each case prior to the Maturity Date,
     (2) the indenture governing such Indebtedness shall have no covenants or
     other requirements more onerous than the Loan Documents, (3) the aggregate
     outstanding face amount of such Indebtedness shall not exceed $400,000,000,
     (4) all of the net proceeds of such originally issued Indebtedness shall be
     used to repay Loans to Borrower, (5) upon the receipt of net proceeds from
     the original issuance of such Indebtedness, the Commitment shall be
     permanently reduced by an amount equal to (A) forty percent (40%) of the
     face amount of such Indebtedness, if the aggregate face amount is less than
     $350,000,000, or (B) fifty percent (50%) of the face amount of such
     Indebtedness, if the aggregate face amount of such bonds is equal to or
     greater than $350,000,000, and (6) both immediately prior to and
     immediately following the consummation of such offering, no Default or
     Event of Default shall have occurred and be continuing.

     The reference to "$25,000,000" set forth in Section 7.1(g) of the Original
Agreement (to be redesignated as clause (h) as set forth in the prior paragraph
hereof) is hereby amended to refer instead to "the Dollar Equivalent of
$25,000,000".

     (S) 2.5.  Limitation on Sales of Property.  The reference to "$10,000,000"
set forth in Section 7.5(c) of the Original Agreement is hereby amended to refer
instead to "the Dollar Equivalent of $10,000,000".

     (S) 2.6.  Debt Coverage Ratio.  Section 7.12 of the Original Agreement is
hereby amended in its entirety to read as follows:

          Section 7.12.  Debt Coverage Ratio.  (a) At the end of any Fiscal
     Quarter, (b) on any date on which General Partner declares a distribution
     permitted under Section 7.6 and (c) on the date of any Permitted
     Acquisition, both immediately prior to and after giving effect to the
     consummation thereof, the Debt Coverage Ratio will not be greater than:

               (i) prior to both the CanPet Acquisition Closing Date and Murphy
          Acquisition Closing Date: (A) 4.0 to 1.0, in the case of any
          determination during the period from the date hereof through and
          including March 31, 2002, and (B) 3.75 to 1.0, in the case of any
          determination thereafter;

               (ii) on and after the CanPet Acquisition Closing Date, and prior
          to the Murphy Acquisition Closing Date (if the CanPet Acquisition
          Closing Date shall occur prior to the Murphy Acquisition Closing
          Date): (I) 4.25 to 1.0, in the case of any determination during the
          period from the date hereof through and including December 30, 2002,
          and (II) 4.00 to 1.0, in the case of any determination thereafter; and

                                                       Revolving Credit Facility

                                       8

               (iii) on and after the Murphy Acquisition Closing Date (whether
     or not the CanPet Acquisition Closing Date has occurred): (A) 4.75 to 1.0,
     in the case of any determination during the period from the date hereof
     through and including September 29, 2001, (B) 4.50 to 1.0, in the case of
     any determination during the period from September 30, 2001 through and
     including June 29, 2002, (C) 4.25 to 1.0, in the case of any determination
     from June 30, 2002 through and including December 30, 2002, and (D) 4.00 to
     1.0, in the case of any determination thereafter.

     As used herein, "Debt Coverage Ratio" means the ratio of (a) Consolidated
     Funded Indebtedness to (b) Consolidated EBITDA for the four Fiscal Quarter
     period (or other period specified below) most recently ended prior to the
     date of determination for which financial statements contemplated by
     Section 6.2(a) or (b) are available to Borrower; provided, for purposes of
     this Section 7.12, if, since the beginning of the four Fiscal Quarter
     period ending on the date for which Consolidated EBITDA is determined, any
     Restricted Person shall have made any asset disposition or acquisition,
     shall have consolidated or merged with or into any Person (other than
     another Restricted Person), or shall have made any disposition or
     acquisition of a Restricted Person, Consolidated EBITDA shall be calculated
     giving pro forma effect thereto as if the disposition, acquisition,
     consolidation or merger had occurred on the first day of such period. Such
     pro forma effect shall be determined (i) in good faith by the chief
     financial officer of Borrower, and (ii) without giving effect to any
     anticipated or proposed change in operations, revenues, expenses or other
     items included in the computation of Consolidated EBITDA, except with the
     consent of Majority Lenders.

     (S) 2.7.  Debt to Capital Ratio.  Section 7.14 of the Original Agreement is
hereby amended in its entirety to read as follows:

          Section 7.14  Debt to Capital Ratio.  The ratio of (a) all
     Consolidated Funded Indebtedness to (b) the sum of Consolidated Funded
     Indebtedness plus Consolidated Net Worth will never be greater than:

               (i) prior to both the CanPet Acquisition Closing Date and the
          Murphy Acquisition Closing Date: 0.65 to 1.0 at any time;

               (ii) on and after the CanPet Acquisition Closing Date, and prior
          to the Murphy Acquisition Closing Date (if the CanPet Acquisition
          Closing Date shall occur prior to the Murphy Acquisition Closing
          Date): 0.67 to 1.0 at any time prior to December 30, 2002, and 0.65 to
          1.0 thereafter; and

               (iii) on and after the Murphy Acquisition Closing Date (whether
          or not the CanPet Acquisition Closing Date has occurred): 0.73 to 1.0
          at any time prior to December 30, 2002, and 0.65 to 1.0 thereafter.

                                                       Revolving Credit Facility

                                       9

     (S) 2.8.  Events of Default.  The references to "$2,500,000" set forth in
Section 8.1(g), 8.1(i)(iv), 8.1(i)(v) and 8.1(i)(vi) of the Original Agreement
are hereby amended to refer instead to "the Dollar Equivalent of $2,500,000".

     (S) 2.9.  Lender Schedules.  Each Lender's Initial Commitment and
Percentage Share set forth on its Lender Schedule attached as Schedule 1 to the
Original Agreement is hereby amended to refer instead to such Lender's Initial
Commitment and Percentage Share as set forth opposite its signature block
hereon.  Schedule 1 to the Original Agreement is further hereby amended by
adding new Lender Schedules to read as set forth on the Lender Schedules
attached hereto.  The Composite Lender Schedule set forth on the last page of
the Lender Schedule attached as Schedule 1 to the Original Agreement is hereby
amended in its entirety to read as set forth on the Composite Lender Schedule
attached hereto.

     (S) 2.10. Schedules and Exhibits.  Schedule 3 and Exhibit A attached to the
Original Agreement are hereby amended in their respective entirety to read as
set forth on Schedule 3 and Exhibit A attached hereto.

     (S) 2.11. Consent to Transfers and Issuances of Limited Partner Interests
in Plains Marketing Canada, L.P.  As of the date hereof, Plains Marketing Canada
LLC, a Delaware limited liability company, owns all of the outstanding limited
partner interests in Plains Marketing Canada, L.P., an Alberta limited
partnership.  Lenders hereby consent to the transfer by Plains Marketing Canada
LLC, a Delaware limited liability company, of any or all such outstanding
limited partner interests in Plains Marketing Canada, L.P. to Borrower, and
waive any Default or Event of Default under Section 7.4(b) or Section 7.7 of the
Credit Agreement caused thereby.

     As of the date hereof, all of the outstanding limited partner interests in
Plains Marketing Canada, L.P., an Alberta limited partnership, are owned,
directly or indirectly, by Borrower. Lenders hereby consent to the issuance by
Plains Marketing Canada, L.P., an Alberta limited partnership, of limited
partner interests to CanPet Energy Group (USA), Inc. or CanPet Energy Group Inc.
to effect the consummation of the CanPet Acquisition as set forth in the CanPet
Acquisition Documents, and waive any Default or Event of Default under Section
7.4 or Section 7.6 of the Credit Agreement caused thereby, provided, such
limited partner interests shall:

          (i) pay no cash dividend nor entitle the holder thereof to any cash
     distribution, except upon dissolution (provided that the foregoing shall
     not prevent the accrual of any such dividends or distributions);

          (ii) not entitle the holder thereof to any right to manage or control
     Plains Marketing Canada, L.P. or vote with respect thereto; and

          (iii)  not be redeemable or exchangeable by the holder thereof for
     cash or callable or subject to a put option for cash at the option of any
     such holder.

                                                       Revolving Credit Facility

                                       10

     In the event any limited partner interests issued by Plains Marketing
Canada, L.P., an Alberta limited partnership, to CanPet Energy Group (USA), Inc.
or CanPet Energy Group Inc. are exchanged for units issued by Plains MLP,
Lenders hereby consent to the contribution by Plains MLP to Borrower of any and
all such partnership interests, and waive any Default or Event of Default under
Section 7.4(c) or Section 7.5 of the Credit Agreement caused thereby.

     (S) 2.12. Consent to CanPet Acquisition.  Lenders hereby consent to the
CanPet Acquisition (as defined in the Credit Agreement as amended hereby),
subject to the following:

          (a) Administrative Agent shall have received and approved copies of
     all environmental evaluations, reports or reviews related to properties to
     be acquired pursuant to the CanPet Acquisition, and there shall be no
     existing or potential environmental liabilities disclosed thereunder or
     otherwise existing except as disclosed by Borrower to Administrative Agent
     and Lenders prior to the date hereof.

          (b) Administrative Agent and each Lender shall have received any
     updated or revised business and/or financial projections with respect to
     the assets and operations to be acquired pursuant to the CanPet
     Acquisition, and no such projection shall materially and adversely differ
     from those projections previously delivered to Administrative Agent and
     Lenders.

          (c) The CanPet Acquisition shall exclude the acquisition of any
     existing or potential environmental or litigation liabilities incurred
     prior to the CanPet Acquisition Closing Date, except as disclosed by
     Borrower to Administrative Agent and Lenders prior to the date hereof, and
     Borrower and Plains Marketing Canada, L.P., as acquirers, shall have
     received an environmental indemnity providing for a deductible of not more
     than C$50,000 in the aggregate (not applicable with respect to
     environmental liabilities disclosed to Administrative Agent and Lenders
     prior to the date hereof) and a cap of not less than C$3,000,000 in the
     aggregate, to be effective for not less than two years with respect to on-
     site contamination and three years with respect to off-site contamination
     following the CanPet Acquisition Closing Date, and otherwise reasonably
     satisfactory to Administrative Agent with respect to such liabilities.

          (d) Administrative Agent  shall have received and approved copies of
     all CanPet Acquisition Documents and all other related documents as
     Administrative Agent may request.

          (e) The cash portion of the purchase price shall not exceed
     $26,000,000.

          (f) Both immediately prior to and immediately following the
     consummation of the CanPet Acquisition, no Material Adverse Change shall
     have occurred since December 31, 1999, and no Default or Event of Default
     shall have occurred and be continuing.

                                                       Revolving Credit Facility

                                       11

          (g) Canadian Subsidiaries shall have delivered Security Documents
     pursuant to Section 6.14 of the Credit Agreement with respect to the
     properties acquired pursuant to the CanPet Acquisition, the definition of
     "Marketing Credit Priority Collateral" set forth in the Intercreditor
     Agreement dated May 8, 2000 among the Administrative Agent, Lenders and the
     administrative agent and lenders under the Marketing Credit Agreement shall
     be amended to include properties of the type described therein owned by
     Canadian Subsidiaries as well as Borrower, and pursuant thereto such Liens
     on such Canadian Subsidiaries' property securing the Obligations shall be
     subordinated to the Liens on such Canadian Subsidiaries' property securing
     the Indebtedness under the Marketing Credit Agreement.

     (S) 2.13. Consent to Murphy Acquisition.  Lenders hereby consent to the
Murphy Acquisition, subject to the following:

          (a) Administrative Agent shall have received and approved copies of
     all environmental evaluations, reports or reviews related to properties to
     be acquired pursuant to the Murphy Acquisition, and there shall be no
     existing or potential environmental liabilities disclosed thereunder or
     otherwise existing except as disclosed by Borrower to Administrative Agent
     and Lenders prior to the date hereof.

          (b) Administrative Agent and each Lender shall have received any
     updated or revised business and/or financial projections with respect to
     the assets and operations to be acquired pursuant to the Murphy
     Acquisition, and no such projection shall materially and adversely differ
     from those projections previously delivered to Administrative Agent and
     Lenders.

          (c) The Murphy Acquisition shall exclude the acquisition of any
     existing or potential environmental or litigation liabilities incurred
     prior to the Murphy Acquisition Closing Date, except as disclosed by
     Borrower to Administrative Agent and Lenders prior to the date hereof, and
     Plains Marketing Canada, L.P., as acquirer, shall have received an
     environmental indemnity with respect to all environmental liabilities
     disclosed to Administrative Agent and Lenders prior to the date hereof and
     further providing for a deductible of not more than $300,000 in the
     aggregate, with a $20,000 deductible per site thereafter, and a cap of not
     less than $3,000,000 in the aggregate, with respect to all other
     environmental liabilities, and otherwise reasonably satisfactory to
     Administrative Agent with respect to such liabilities.

          (d) Administrative Agent  shall have received and approved copies of
     all Murphy Acquisition Documents and all other related documents as
     Administrative Agent may request.

          (e) The cash portion of the purchase price shall not exceed
     $155,000,000 (subject to upward adjustment for net working capital
     adjustments not to exceed $6,000,000 in the aggregate).

                                                       Revolving Credit Facility

                                       12

          (f) Both immediately prior to and immediately following the
     consummation of the Murphy Acquisition, no Material Adverse Change shall
     have occurred since December 31, 1999, and no Default or Event of Default
     shall have occurred and be continuing.

          (g) On the Murphy Acquisition Closing Date: (1) Canadian Subsidiaries
     shall on the Murphy Acquisition Closing Date deliver Security Documents
     pursuant to Section 6.14 of the Credit Agreement (together with opinions of
     legal counsel for Canadian Subsidiaries and related corporate documents and
     records; documents evidencing governmental authorizations, consents,
     approvals, licenses and exemptions; and certificates of public officials
     and of officers and representatives of Restricted Persons as Administrative
     Agent may request) with respect to all of their properties, and (2) the
     Intercreditor Agreement dated May 8, 2000 among the Administrative Agent,
     Lenders and the administrative agent and lenders under the Marketing Credit
     Agreement shall be amended and restated to, among other things, amend the
     definition of "Marketing Credit Priority Collateral" to include properties
     of the type described therein owned by Canadian Subsidiaries as well as
     Borrower, and pursuant thereto such Liens on such Canadian Subsidiaries'
     property securing the Obligations shall be subordinated to the Liens on
     such Canadian Subsidiaries' property securing the Indebtedness under the
     Marketing Credit Agreement.

     (S) 2.14. Consent to Restated Agreement.  Lenders hereby consent to (a) the
addition to the Credit Agreement of a $100,000,000 term loan facility to PMC
(Nova Scotia) Company, a Nova Scotia unlimited liability company and a Canadian
Subsidiary, and $30,000,000 Canadian working capital revolving credit facility
to PMC (Nova Scotia) Company, a Nova Scotia unlimited liability company, or
Plains Marketing Canada, L.P., an Alberta limited partnership, or both of them
if applicable, to be funded in connection with the consummation of the Murphy
Acquisition, pursuant to the terms and conditions set forth on the indicative
term sheet attached hereto as Annex I, and to permit the extensions of credit
from time to time outstanding thereunder and the accrued interest and fees in
respect thereof to share ratably in the benefits of this Agreement and the other
Loan Documents with the Loans and LC Obligations and the accrued interest and
fees in respect thereof and pari passu with respect to all Collateral
thereunder, subject only to the Intercreditor Agreement described in Section
2.12, and (b) the inclusion of the outstanding commitments of all lenders under
the Credit Agreement, whether Lenders, term lenders or Canadian working capital
revolver lenders, whether drawn or undrawn, in any determination of Majority
Lenders (other than with respect to extensions of maturity or reductions in
amortization of a facility, which shall include only the commitments of lenders
under such facility with respect to determinations thereof).

     In furtherance of the foregoing, each Lender hereby acknowledges and agrees
that it shall, subject to reasonable documentation review and approval of
Majority Lenders, execute and deliver (a) an amended and restated credit
agreement, adding such facilities to the Credit Agreement, and (b) an amended
and restated intercreditor agreement among all lenders under the facilities
under the Credit Agreement, as so amended and restated, and under the Marketing
Credit Agreement, providing for, among other things (i) such ratable sharing and
voting among

                                                       Revolving Credit Facility

                                       13

all lenders under the facilities under the Credit Agreement as so amended and
restated as set forth above and (ii) an amendment to the definition of
"Marketing Credit Priority Collateral" in the existing Intercreditor Agreement
to include properties of the type described therein owned by Canadian
Subsidiaries as well as Borrower, and pursuant thereto Liens on all other
property securing the Indebtedness under the Marketing Credit Agreement shall be
subordinated to the Liens on such property securing the Obligations, and Liens
on such "Marketing Credit Priority Collateral" securing the Obligations shall be
subordinated to the Liens on such "Marketing Credit Priority Collateral"
securing the Indebtedness under the Marketing Credit Agreement. In consideration
of each Lender's execution and delivery of this Agreement and such Lender's
agreement to execute and deliver such amended and restated credit agreement and
intercreditor agreement, Borrower hereby agrees to pay to Administrative Agent
for the account of each Lender the amendment fees and/or work fees set forth in
that certain letter of even date herewith between Borrower and Administrative
Agent, on behalf of Lenders.

                  ARTICLE III. -- Conditions of Effectiveness

     (S) 3.1.  Effective Date.  This Amendment shall become effective as of the
date first above written when, and only when:

     (a) Administrative Agent shall have received, at Administrative Agent's
office, a counterpart of this Amendment executed and delivered by Borrower and
Majority Lenders (and with respect to Section 2.1(i), all Lenders), and
consented to by each Guarantor;

     (b) Borrower shall have issued and delivered to Administrative Agent, for
subsequent delivery to each Lender, a Renewal Note with appropriate insertions
payable to the order of such Lender, duly executed on behalf of Borrower, dated
the date hereof,

     (c) Restricted Persons shall have executed and delivered to Administrative
Agent Amendments to Security Documents amending the description of the secured
indebtedness therein to reflect the issuance of the Renewal Notes;

     (d) Administrative Agent shall have received an amendment fee paid by
Borrower for the account of each Lender equal to 0.15% of the amount such
Lender's revised Commitment set forth opposite its signature block hereto
exceeds such Lender's Commitment immediately prior to the effectiveness hereof,
and all other fees required to be paid to Administrative Agent or any Lender
pursuant to any Loan Documents, including fees and expenses of Thompson & Knight
LLP, counsel to Administrative Agent; and

     (e) Administrative Agent shall have additionally received all of the
following documents, each document (unless otherwise indicated) being dated the
date of receipt thereof by Administrative Agent, duly authorized, executed and
delivered, and in form and substance satisfactory to Administrative Agent:

          (i) Marketing Credit Amendment.  A contemporaneous amendment to the
     Marketing Credit Agreement, decreasing the Maximum Facility Amount to

                                                       Revolving Credit Facility

                                       14

     $200,000,000, consenting to the CanPet Acquisition and the Murphy
     Acquisition on the same terms and conditions set forth herein, amending
     certain financial covenants on the same terms and conditions set forth
     herein, and amending various other provisions therein consistent with the
     amendments set forth herein;

          (ii) Opinions of Counsel for Restricted Persons.  The written opinions
     of Fulbright & Jaworski, L.L.P., special Texas and New York counsel to
     Restricted Persons, and an opinion of Tim Moore, General Counsel for
     Restricted Persons, addressed to Administrative Agent and Lenders, to the
     effect that this Amendment, each Renewal Note and the other Amendment
     Documents have been duly authorized, executed and delivered by Restricted
     Persons, to the extent a party thereto, and that the Credit Agreement, each
     Renewal Note and the other Amendment Documents constitute the legal, valid
     and binding obligations of Restricted Persons, to the extent a party
     thereto, enforceable in accordance with their respective terms (subject, as
     to enforcement of remedies, to applicable bankruptcy, reorganization,
     insolvency and similar laws and to moratorium laws and other laws affecting
     creditors' rights generally from time to time in effect).

          (iii)  Officer's Certificate.  A certificate of a duly authorized
     officer of General Partner stating that all of the representations and
     warranties set forth in Article IV hereof are true and correct at and as of
     the time of such effectiveness.

          (iv)  Supporting Documents.  (I) A Certificate of the Secretary of
     General Partner dated the date of this Amendment certifying that attached
     thereto is a true and complete copy of resolutions adopted by the Board of
     Directors of General Partner authorizing the execution, delivery and
     performance of this Amendment, each Renewal Note and the other Amendment
     Documents by Restricted Persons and certifying the names and true
     signatures of the officers of General Partner authorized to sign this
     Amendment, each Renewal Note and the other Amendment Documents on behalf of
     Restricted Persons, and (II) such supporting documents as Administrative
     Agent may request.

                 ARTICLE IV. -- Representations and Warranties

     (S) 4.1.  Representations and Warranties of Plains MLP and Borrower.  In
order to induce Administrative Agent and Lenders to enter into this Amendment,
Plains MLP and Borrower represent and warrant to Administrative Agent and each
Lender that:

          (a) The representations and warranties contained in Article V of the
     Original Agreement are true and correct at and as of the time of the
     effectiveness hereof, except to the extent that such representation and
     warranty was made as of a specific date.

          (b) Each Restricted Person is duly authorized to execute and deliver
     this Amendment, each Renewal Note and each other Amendment Document, to the
     extent a party thereto, and Borrower is and will continue to be duly
     authorized to borrow and perform its obligations under the Credit
     Agreement.  Each Restricted Person has duly taken all action necessary to
     authorize the execution and delivery of this Amendment,

                                                       Revolving Credit Facility

                                       15

     each Renewal Note and each other Amendment Document, to the extent a party
     thereto, and to authorize the performance of their respective obligations
     hereunder.

          (c) The execution and delivery by each Restricted Person of this
     Amendment, each Renewal note and each other Amendment Document, to the
     extent a party thereto, the performance by each Restricted Person of its
     respective obligations hereunder and thereunder, and the consummation of
     the transactions contemplated hereby and thereby, do not and will not
     conflict with any provision of any Law or of the organizational documents
     of any Restricted Person, or of any material agreement, judgment, license,
     order or permit applicable to or binding upon any Restricted Person, or
     result in the creation of any Lien upon any assets or properties of any
     Restricted Person, except in favor of Administrative Agent for the benefit
     of Lenders and other Permitted Liens. Except for those which have been duly
     obtained, no consent, approval, authorization or order of any Tribunal or
     third party is required in connection with the execution and delivery by
     any Restricted Person of this Amendment, any Renewal Note or any other
     Amendment Document, or to consummate the transactions contemplated hereby
     and thereby.

          (d) When duly executed and delivered, each of this Amendment, each
     Renewal Note, each other Amendment Document, and each of the Loan
     Documents, as amended hereby and thereby, will be a legal and binding
     instrument and agreement of each Restricted Person to the extent a party
     thereto, enforceable in accordance with its terms, (subject, as to
     enforcement of remedies, to applicable bankruptcy, insolvency and similar
     laws applicable to creditors' rights generally).

          (e) The business and financial projections with respect to the assets
     and operations to be acquired pursuant to the CanPet Acquistion and the
     Murphy Acquisition previously delivered to Administrative Agent and Lenders
     fairly present Restricted Persons' best projections with respect thereto,
     and are based on reasonable historical business assumptions with respect to
     such assets and operations as well as Restricted Persons' current business
     operations and financial performance.  No Material Adverse Change has
     occurred since December 31, 1999.

                          ARTICLE V. -- Miscellaneous

     (S) 5.1.  Ratification of Agreements.  The Original Agreement, as hereby
amended, is hereby ratified and confirmed in all respects.  The Loan Documents
(including but not limited to each Guaranty), as they may be amended or affected
by this Amendment or any other Amendment Document, are hereby ratified and
confirmed in all respects by each Restricted Person to the extent a party
thereto.  Any reference to the Credit Agreement in any Loan Document shall be
deemed to refer to this Amendment also.  Any reference to the Notes in any other
Loan Document shall be deemed to be a reference to the Renewal Notes issued and
delivered pursuant to this Amendment.   The execution, delivery and
effectiveness of this Amendment, the Renewal Notes and the other Amendment
Documents shall not, except as expressly provided herein, operate as a waiver of
any right, power or remedy of Administrative

                                                       Revolving Credit Facility

                                       16

Agent or any Lender under the Credit Agreement or any other Loan Document nor
constitute a waiver of any provision of the Credit Agreement or any other Loan
Document.

     (S) 5.2.  Ratification of Security Documents.  Restricted Persons,
Administrative Agent, and Lenders each acknowledge and agree that any and all
indebtedness, liabilities or obligations arising under or in connection with the
LC Obligations, as amended hereby, or the Notes, as amended hereby, are
Obligations and are secured indebtedness under, are guarantied by, and are
secured by, each and every Security Document to which any Restricted Person is a
party.  Each Restricted Person hereby re-pledges, re-grants and re-assigns a
security interest in and lien on every asset of the such Restricted Person
described as Collateral in any Security Document and re-guarantees all
Obligations, as amended hereby.

     (S) 5.3.  Ratification of Intercreditor Agreement.  Each Lender hereby
acknowledges and confirms that all Obligations under the Credit Agreement, as
amended hereby, and the "Obligations" under the Marketing Credit Agreement, as
amended on the date hereof, shall be and shall remain subject to the terms and
entitled to the benefits of the Intercreditor Agreement.

     (S) 5.4.  Survival of Agreements.  All representations, warranties,
covenants and agreements of the Restricted Persons herein shall survive the
execution and delivery of this Amendment and the performance hereof, including
without limitation the making or granting of each Loan and the issuance and
delivery of the Renewal Notes, and shall further survive until all of the
Obligations are paid in full.  All statements and agreements contained in any
certificate or instrument delivered by any Restricted Person hereunder or under
the Credit Agreement to Administrative Agent or any Lender shall be deemed to
constitute representations and warranties by, or agreements and covenants of,
such Restricted Person under this Amendment and under the Credit Agreement.

     (S) 5.5.  Loan Documents.  This Amendment, each Renewal Note, and each
other Amendment Document is a Loan Document, and all provisions in the Credit
Agreement pertaining to Loan Documents apply hereto.

     (S) 5.6.  GOVERNING LAW.  THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED
IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND ANY APPLICABLE LAWS OF
THE UNITED STATES OF AMERICA IN ALL RESPECTS, INCLUDING CONSTRUCTION, VALIDITY
AND PERFORMANCE.

     (S) 5.7.  Counterparts.  This Amendment may be separately executed in
counterparts and by the different parties hereto in separate counterparts, each
of which when so executed shall be deemed to constitute one and the same
Amendment.

                                                       Revolving Credit Facility

                                       17

     IN WITNESS WHEREOF, this Amendment is executed as of the date first above
written.

                              PLAINS MARKETING, L.P.

                              By:   PLAINS ALL AMERICAN INC.,
                                    its general partner

                                    By:   /s/ Phil Kramer
                                       ------------------
                                       Phil Kramer
                                       Executive Vice President

                              PLAINS ALL AMERICAN PIPELINE, L.P.

                              By:   PLAINS ALL AMERICAN INC.,
                                    its general partner

                                    By:   /s/ Phil Kramer
                                       ------------------
                                       Phil Kramer
                                       Executive Vice President

                              ALL AMERICAN PIPELINE, L.P.

                              By:   PLAINS ALL AMERICAN INC.,
                                    its general partner

                                    By:   /s/ Phil Kramer
                                       ------------------
                                       Phil Kramer
                                       Executive Vice President

                                                       Revolving Credit Facility

                                       18

Lender's Initial Commitment: $71,904,761,91   FLEET NATIONAL BANK,
Percentage Share:            15.244826%       as Administrative Agent and
Lender

                                              By:   /s/   Terrence Ronan
                                                  -----------------------
                                                  Terrence Ronan,
                                                  Managing Director

Lender's Initial Commitment: $61,666,666.67   FIRST UNION NATIONAL BANK, Lender
Percentage Share:            13.074205%
                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $61,666,666.67   BANK OF AMERICA, N.A., Lender
Percentage Share:            13.074205%
                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $46,666,666.67   BANK ONE, NA (MAIN OFFICE
Percentage Share:            9.893993%        CHICAGO), successor by merger to
                                              Bank One Texas, N.A.,  Lender

                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $51,666,666.67   FORTIS CAPITAL CORP., Lender
Percentage Share:            10.954064%
                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

                                                       Revolving Credit Facility

                                       19

Lender's Initial Commitment: $21,333,333.33   U.S. BANK NATIONAL ASSOCIATION,
Percentage Share:            4.522968%        Lender

                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $24,976,190.47   BANK OF SCOTLAND, Lender
Percentage Share:            5.295305%
                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $21,333,333.33   WELLS FARGO BANK (TEXAS),
Percentage Share:            4.522968%        NATIONAL ASSOCIATION, Lender

                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $25,000,000      THE BANK OF NOVA SCOTIA, Lender
Percentage Share:            5.300353%
                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $17,833,333.33   CREDIT AGRICOLE INDOSUEZ, Lender
Percentage Share:            3.780919%
                                              By:  /s/
                                                  -------------------------
                                                  Name:
                                                  Title:

                                                       Revolving Credit Facility

                                       20

Lender's Initial Commitment: $6,666,666.67    GUARANTY FEDERAL BANK, F.S.B.,
Percentage Share:            1.413428%        Lender

                                              By:  /s/
                                                  --------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $21,428,571.43   TORONTO DOMINION (TEXAS), INC.,
Percentage Share:            4.543160%        Lender

                                              By:  /s/
                                                  --------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $10,714,285.71   SOUTHWEST BANK OF TEXAS, N.A.,
Percentage Share:            2.271580%        Lender

                                              By:  /s/
                                                  --------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $21,666,666.67   UNION BANK OF CALIFORNIA, Lender
Percentage Share:            4.593640%
                                              By:  /s/
                                                  --------------------------
                                                  Name:
                                                  Title:

Lender's Initial Commitment: $7,142,857.14    COMERICA BANK-TEXAS, Lender
Percentage Share:            1.514387%
                                              By:   /s/
                                                  --------------------------
                                                  Name:
                                                  Title:

                                                       Revolving Credit Facility

                                       21

                             CONSENT AND AGREEMENT

     Each of the undersigned Guarantors hereby consents to the provisions of
this Amendment and the execution and delivery of the Renewal Notes and the other
Amendment Documents, and the transactions contemplated herein and therein and
hereby and thereby (i) acknowledges and agrees that any and all indebtedness,
liabilities or obligations arising under or in connection with the Renewal Notes
are Obligations and are secured indebtedness under, and are secured by, each and
every Security Document to which it is a party, (ii) re-pledges, re-grants and
re-assigns a security interest in and lien on all of its assets described as
collateral in any Security Document, (iii) ratifies and confirms its Guaranty
made by it for the benefit of Administrative Agent and Lenders, and (iv)
expressly acknowledges and agrees that such Guarantor guarantees all
indebtedness, liabilities and obligations arising under or in connection with
the Renewal Notes pursuant to the terms of such Guaranty, and agrees that its
obligations and covenants thereunder are unimpaired hereby and shall remain in
full force and effect.

                         PLAINS MARKETING CANADA LLC

                         By:  Plains Marketing, L.P., its sole member

                              By:   Plains All American Inc.,
                                    its general partner

                                    By:   /s/ Phil Kramer
                                       ---------------------------------
                                       Phil Kramer, Exec. Vice President

                         PMC (NOVA SCOTIA) COMPANY

                         By:   /s/ Phil Kramer
                            ---------------------------------
                            Phil Kramer, Exec. Vice President

                         PLAINS MARKETING CANADA, L.P.

                         By:  PMC (Nova Scotia) Company,
                              its general partner

                              By:   /s/ Phil Kramer
                                 ---------------------------------
                                 Phil Kramer, Exec. Vice President

                                                       Revolving Credit Facility

                                       22

                                                                   Exhibit 10.18

                                                                  Execution Copy
                      FIRST AMENDMENT TO CREDIT AGREEMENT
                [Letter of Credit and Hedged Inventory Facility]

     THIS FIRST AMENDMENT TO CREDIT AGREEMENT (this "Amendment") dated as of the
26th day of February, 2001, by and among PLAINS MARKETING, L.P. ("Borrower"),
ALL AMERICAN PIPELINE, L.P. ("All American") and PLAINS ALL AMERICAN PIPELINE,
L.P. ("Plains MLP"), as guarantors, FLEET NATIONAL BANK, as Administrative Agent
(in such capacity, "Administrative Agent"), and the Lenders party hereto.

                              W I T N E S S E T H:

     WHEREAS, Borrower, All American, Plains MLP, Administrative Agent and
Lenders entered into that certain Credit Agreement [Letter of Credit and Hedged
Inventory Facility] dated as of May 8, 2000 (as amended, restated, or
supplemented to the date hereof, the "Original Agreement") for the purposes and
consideration therein expressed, pursuant to which Lenders became obligated to
make and made loans to Borrower as therein provided; and

     WHEREAS, Borrower, All American, Plains MLP, Administrative Agent, and
Lenders desire to amend the Original Agreement for the purposes described
herein;

     NOW, THEREFORE, in consideration of the premises and the mutual covenants
and agreements contained herein and in the Original Agreement, in consideration
of the loans which may hereafter be made by Lenders to Borrower, and for other
good and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto do hereby agree as follows:

                    ARTICLE I. -- Definitions and References

     (S) 1.1.  Terms Defined in the Original Agreement.  Unless the context
otherwise requires or unless otherwise expressly defined herein, the terms
defined in the Original Agreement shall have the same meanings whenever used in
this Amendment.

     (S) 1.2.  Other Defined Terms.  Unless the context otherwise requires, the
following terms when used in this Amendment shall have the meanings assigned to
them in this (S) 1.2.

          "Amendment" means this First Amendment to Credit Agreement.

          "Amendment Documents" means this Amendment, the Renewal Notes, and the
     Amendments to Security Documents as described in Section 3.1(c) hereof.

          "Credit Agreement" means the Original Agreement as amended hereby.

          "Original Notes" means the "Notes" referred to and defined as such in
     the Original Agreement.

                                                    LC/Hedged Inventory Facility

                                       1

          "Renewal Notes" means the renewal promissory notes of Borrower in the
     form attached hereto as Exhibit A, expressly renewing and extending the
     Original Notes.

                           ARTICLE II. -- Amendments

     (S) 2.1.  Definitions.  (a)  Applicable Leverage Level.  The table set
forth in the definition of "Applicable Leverage Level" set forth in Section 1.1
of the Original Agreement is hereby amended in its entirety to read as follows:

   Applicable
 Leverage Level                     Leverage Ratio
- -----------------        ------------------------------------
     Level I             greater than or equal to 4.50 to 1.0

     Level II            greater than or equal to 4.25 to 1.0
                              but less than 4.50 to 1.0

     Level III           greater than or equal to 4.00 to 1.0
                              but less than 4.25 to 1.0

     Level IV            greater than or equal to 3.50 to 1.0
                              but less than 4.00 to 1.0

     Level V             greater than or equal to 3.00 to 1.0
                              but less than 3.50 to 1.0

     Level VI            greater than or equal to 2.25 to 1.0
                              but less than 3.00 to 1.0

     Level VII           greater than or equal to 1.75 to 1.0
                              but less than 2.25 to 1.0

     Level VIII                 less than 1.75 to 1.0

     (b) Base Rate Margin:    The table set forth in the definition of "Base
Rate Margin" set forth in Section 1.1 of the Original Agreement is hereby
amended in its entirety to read as follows:

    Applicable Leverage Level        Base Rate Margin
- -----------------------------------------------------
Level I, Level II, Level III or                 0.250%
  Level IV
- -----------------------------------------------------
Level V                                         0.125%
- -----------------------------------------------------
Level VI, Level VII or                          0.000%
  Level VIII
- -----------------------------------------------------

                                                    LC/Hedged Inventory Facility

                                       2

     (c) Commitment Fee Rate.  The table set forth in the definition of
"Commitment Fee Rate" set forth in Section 1.1 of the Original Agreement is
hereby amended in its entirety to read as follows:

     Applicable Leverage Level        Commitment Fee Rate
- ---------------------------------------------------------
Level I or Level II or Level III                    0.500%
 or Level IV or Level V
- ---------------------------------------------------------
Level VI or Level VII                               0.375%
- ---------------------------------------------------------
Level VIII                                          0.250%
- ---------------------------------------------------------

     (d) Commitment Period.  The reference to "April 30, 2003" set forth in the
definition of "Commitment Period" set forth in Section 1.1 of the Original
Agreement is hereby amended to refer instead to "April 30, 2004".

     (e) Consolidated EBITDA.  Clause (5) of the definition of "Consolidated
EBITDA" set forth in Section 1.1 of the Original Agreement is hereby renumbered
clause (6), and a new clause (5) is hereby added immediately before "minus"
preceding such clause (6), to read as follows:

     plus (5) settlement payments made in such period with respect to litigation
     arising out of the unauthorized trading activity by Borrower during the
     period of January 1, 1999 to November 20, 1999, not to exceed an aggregate
     amount of $6,963,000

     (f) Consolidated Funded Indebtedness.  The proviso at the end of the last
sentence of the definition of "Consolidated Funded Indebtedness" set forth in
Section 1.1 of the Original Agreement is hereby amended in its entirety to read
as follows:

     provided, however, that Consolidated Funded Indebtedness shall not include
     Indebtedness in respect of letters of credit, Cash and Carry Purchases or
     margin deposits.

     (g) Eligible Receivables.  (I) The reference to "Account of the Borrower"
         --------------------
set forth in the introductory clause of the definition of "Eligible Receivables"
set forth in Section 1.1 of the Original Agreement is hereby amended to refer
instead to "Account of the Borrower or Plains Marketing Canada, L.P."; (II) the
references to "Borrower" set forth in clauses (i), (iii), (iv), (v), (viii) and
(ix) of such definition are hereby amended to refer instead to "Borrower or
Plains Marketing Canada, L.P."; (III) the references to "United States dollars"
set forth in clause (ii) of such definition are hereby amended to refer instead
to "Dollars or Canadian Dollars"; (IV) the references to "the United States of
America" set forth in clauses (ii) and (ix) of such definition are hereby
amended to refer instead to "the United States of America or Canada"; (V) the
reference to "$500,000" set forth in clause (vii) is hereby amended to refer
instead to "the Dollar Equivalent of $500,000", and (VI) "and" at the end of
clause (x) of such definition is hereby

                                                    LC/Hedged Inventory Facility

                                       3

deleted, the "." at the end of clause (xi) is hereby amended to "; and", and a
new clause (xii) is hereby added at the end of such definition, to read as
follows:

     (xii) if such Account is an Account owned by Plains Marketing Canada, L.P.,
     to the extent the Lien on such Account in favor of Administrative Agent
     described in clause (vi) above is valid and non-avoidable under applicable
     Law.

     (h) First Purchase Crude Payables.  The reference to "any other state" set
forth in the definition of "First Purchase Crude Payables" set forth in Section
1.1 of the Original Agreement is hereby amended to refer instead to "any other
state or under the laws of Canada or any province thereof".

     (i) LC Application.  The reference to "Borrower" set forth in the
definition of "LC Application" set forth in Section 1.1 of the Original
Agreement is hereby amended to refer instead to "Borrower or Plains Marketing
Canada, L.P.".

     (j) Letter of Credit.  The definition of "Letter of Credit" set forth in
Section 1.1 of the Credit Agreement is hereby amended in its entirety to read as
follows:

          "Letter of Credit" means any letter of credit issued (or deemed issued
     pursuant to the provisions of Section 10.13) by LC Issuer hereunder (i) at
     the application of Borrower, which shall be issued in Dollars, or (ii) with
     respect to Canadian Letters of Credit, at the application of either
     Borrower or Plains Marketing Canada, L.P., which may be issued in either
     Dollars or Canadian Dollars.

     (k) Letter of Credit Fee Rate.  The table set forth in the definition of
"Letter of Credit Fee Rate" set forth in Section 1.1 of the Original Agreement
is hereby amended in its entirety to read as follows:

    Applicable Leverage Level        LC Fee Rate
- ------------------------------------------------
Level I, Level II, Level III or            1.750%
 Level IV
- ------------------------------------------------
Level V                                    1.625%
- ------------------------------------------------
Level VI                                   1.500%
- ------------------------------------------------
Level VII                                  1.250%
- ------------------------------------------------
Level VIII                                 1.000%
- ------------------------------------------------

     (l) LIBOR Rate Margin.  The table set forth in the definition of "LIBOR
Rate Margin" set forth in Section 1.1 of the Original Agreement is hereby
amended in its entirety to read as follows:

                                                    LC/Hedged Inventory Facility

                                       4

    Applicable Leverage Level        LIBOR Rate Margin
- ------------------------------------------------------
Level I, Level II, Level III or                  1.750%
 Level IV
- ------------------------------------------------------
Level V                                          1.625%
- ------------------------------------------------------
Level VI                                         1.500%
- ------------------------------------------------------
Level VII                                        1.250%
- ------------------------------------------------------
Level VIII                                       1.000%
- ------------------------------------------------------

     (m) Material Market Open Position Loss.  The reference to "$5,000,000" set
forth in the definition of "Material Market Open Position Loss" set forth in
Section 1.1 is hereby amended to refer instead to "the Dollar Equivalent of
$5,000,000".

     (n) Maximum Facility Amount.  The definition of "Maximum Facility Amount"
set forth in Section 1.1 of the Original Agreement is hereby amended in its
entirety to read as follows:

          "Maximum Facility Amount" means the amount of $200,000,000, as such
     amount may be reduced by Borrower from time to time as provided in Section
     2.12.

     (o) Other Priority Claims.  The references to "Borrower" set forth in the
definition of "Other Priority Claims" set forth in Section 1.1 of the Original
Agreement are hereby amended to refer instead to "Borrower or Plains Marketing
Canada, L.P.".

     (p) Paid but Unexpired Letters of Credit.  The reference to "Borrower" set
forth in the second sentence of the definition of "Paid but Unexpired Letters of
Credit" set forth in Section 1.1 of the Original Agreement is hereby amended to
refer instead to "Borrower or Plains Marketing Canada, L.P.".

     (q) Permitted Investments.  Clause (c) of the definition of "Permitted
Investments" set forth in Section 1.1 of the Original Agreement is hereby
amended in its entirety to read as follows:

     (c) Investments by Plains MLP or any of its Subsidiaries in:

          (I) any Wholly Owned Subsidiary of Plains MLP which is a Guarantor,
     other than any Canadian Subsidiary or

          (II) any Canadian Subsidiary, provided that (A) Borrower shall notify
     Administrative Agent and each Lender in the event the aggregate amount of
     such Investments in Canadian Subsidiaries shall exceed $100,000 and (B) the
     aggregate amount of such Investments in Canadian Subsidiaries shall not
     exceed (x) $100,000 in the aggregate prior to the earlier of the CanPet
     Acquisition Closing Date and Murphy

                                                    LC/Hedged Inventory Facility

                                       5

     Acquisition Closing Date, (y) $27,000,000 (exclusive of any Investment
     described in clause (z) below) with respect to the CanPet Acquisition, the
     proceeds of which shall be used to consummate the CanPet Acquisition, to
     fund contango transactions and for working capital purposes with respect to
     the CanPet Acquisition, and (z) $57,000,000 (exclusive of any Investment
     described in clause (y) above) with respect to the Murphy Acquisition, the
     proceeds of which shall be used to consummate the Murphy Acquisition, to
     fund contango transactions and for working capital purposes with respect to
     the Murphy Acquisition.

     The reference to "$5,000,000" set forth in clause (d) of such definition is
hereby amended to refer instead to "the Dollar Equivalent of $5,000,000".

     (r) Revolver Agreement.  The reference to "$400,000,000" set forth in the
definition of "Revolver Agreement" set forth in Section 1.1 of the Original
Agreement is hereby amended to refer instead to "$500,000,000, as amended".

     (s) Canadian Dollars, Canadian Letter of Credit, Canadian Subsidiaries and
CanPet Acquisition.  The following definitions of "Canadian Dollars", "Canadian
Letter of Credit", "Canadian Subsidiaries", "CanPet Acquisition", "Canpet
Acquisition Documents" and "Canpet Closing Date" are hereby added to Section 1.1
of the Original Agreement immediately following the definition of "Business
Day", to read as follows:

          "Canadian Dollars" and "C$" means the lawful currency of Canada.

          "Canadian Letter of Credit" means any Letter of Credit related to a
     purchase or exchange of crude oil in Canada by any Canadian Subsidiary.

          "Canadian Subsidiaries" means each of PMC (Nova Scotia) Company, a
     Nova Scotia unlimited liability company, Plains Marketing Canada, L.P., an
     Alberta limited partnership, and each of their Subsidiaries, whether now
     owned or hereafter acquired.

          "CanPet Acquisition" means the acquisition by Borrower and Plains
     Marketing Canada, L.P. of all or substantially all of the assets of CanPet
     Energy Group (USA), Inc. and CanPet Energy Group Inc., respectively,
     pursuant to the CanPet Acquisition Documents.

          "CanPet Acquisition Documents" means the purchase and sale agreement,
     title transfer documents and all other agreements or instruments executed
     and delivered by Borrower, Plains Marketing Canada, L.P. or any Affiliate
     in connection therewith to consummate the CanPet Acquisition.

          "CanPet Acquisition Closing Date" means the date on which the CanPet
     Acquisition shall have been consummated and Borrower and Plains Marketing
     Canada, L.P. shall have taken good and defensible title to the assets
     subject thereof.

                                                    LC/Hedged Inventory Facility

                                       6

     (t) Dollars and Dollar Equivalent.  The following definitions of "Dollars"
and "Dollar Equivalent" are hereby added to Section 1.1 of the Original
Agreement immediately following the definition of "Disclosure Schedule", to read
as follows:

          "Dollars" and "$" means U.S. dollars except where otherwise specified.

          "Dollar Equivalent" of any amount of any currency at any date means
     (i) if such currency is Dollars, the amount of such currency, or (ii) if
     such currency is Canadian Dollars, the equivalent in Dollars of such amount
     of such currency based upon the rate of exchange for such conversion as
     quoted by the Bank of Canada at approximately 12:00 noon, Toronto time (or,
     if not so quoted, the spot rate of exchange quoted for wholesale
     transactions made by Administrative Agent) on the date on or as of which
     such amount is to be determined.

     (u) Murphy Acquisition.  The following definitions of "Murphy Acquisition",
"Murphy Acquisition Documents" and "Murphy Acquisition Closing Date" are hereby
added to Section 1.1 of the Original Agreement immediately following the
definition of "Moody's", to read as follows:

          "Murphy Acquisition" means the acquisition by Plains Marketing Canada,
     L.P. of certain assets from Murphy Oil Company Ltd. as previously disclosed
     by Borrower to Administrative Agent and Lenders pursuant to the Murphy
     Acquisition Documents.

          "Murphy Acquisition Documents" means the purchase and sale agreement,
     title transfer documents and all other agreements or instruments executed
     and delivered by Plains Marketing Canada, L.P. or any Affiliate in
     connection therewith to consummate the Murphy Acquisition.

          "Murphy Acquisition Closing Date" means the date on which the Murphy
     Acquisition shall have been consummated and Plains Marketing Canada, L.P.
     shall have taken good and defensible title to the assets subject thereof.

     (S) 2.2.  Amendment of Revolver Agreement.  The second sentence of Section
1.3 of the Original Agreement is hereby amended by adding the following phrase
at the end thereof:

     , as amended by the First Amendment to Credit Agreement [Revolving Credit
     Agreement] dated as of February 26, 2001 and as amended and restated as
     contemplated by and provided for in such First Amendment.

     (S) 2.3.  Commitments to Lend.  The reference to "Facility Usage" set forth
in clause (c) of Section 2.1 of the Original Agreement is hereby amended to
refer instead to "Dollar Equivalent of the Facility Usage".

     (S) 2.4.  Use of Proceeds.  The first two sentences of Section 2.4 of the
Original Agreement are hereby amended in their entirety to read as follows:

                                                    LC/Hedged Inventory Facility

                                       7

     Borrower shall use the proceeds of all Loans to finance Cash and Carry
     Purchases, as margin deposits not to exceed $50,000,000 in the aggregate at
     any time outstanding with respect to Hedging Contracts as permitted
     pursuant to Section 7.2(e) and to refinance Matured LC Obligations.
     Borrower and, with respect to Canadian Letters of Credit, Borrower or
     Plains Marketing Canada, L.P., as the case may be, shall use all Letters of
     Credit solely for the purposes specified in Section 2.7(d).

     (S) 2.5.  Mandatory Prepayments.  The reference to "Facility Usage" set
forth in the first sentence of Section 2.6 of the Original Agreement is hereby
amended to refer instead to "Dollar Equivalent of the Facility Usage".

     (S) 2.6.  Letters of Credit.   The reference to "Borrower" set forth in the
introductory clause of Section 2.7 of the Original Agreement is hereby amended
to refer instead to "Borrower and, with respect to Canadian Letters of Credit,
Borrower or Plains Marketing Canada, L.P.".

     The reference to "Facility Usage" set forth in Section 2.7(a) of the
Original Agreement is hereby amended to refer instead to "Dollar Equivalent of
the Facility Usage".

     The reference to "with respect to outstanding letters of credit issued by
LC Issuer under the Scurlock Agreement, by Scurlock," set forth in Section
2.7(d) of the Original Agreement is hereby amended to refer instead to "with
respect to any purchase or exchange in Canada, by Borrower or by Plains
Marketing Canada, L.P.,".

     Clause (e) of Section 2.7 of the Original Agreement is hereby redesignated
clause (f), a new clause (e) is hereby added immediately before such clause (f),
to read as follows:

          (e) if such Letter of Credit is a Canadian Letter of Credit, after
     taking such Canadian Letter of Credit into account, the Dollar Equivalent
     of the aggregate amount of LC Obligations at such time relating to Canadian
     Letters of Credit does not exceed (1) $50,000,000 prior to the Murphy
     Acquisition Closing Date, (2) $80,000,000 during the four-month period
     commencing with the Murphy Acquisition Closing Date, and (3) $50,000,000
     thereafter

and the reference to "conditions (a) through (e)" set forth in the sentence
following such clause (f) is hereby amended to refer instead to "conditions (a)
through (f)".

     The following two new sentences are hereby added at the end of Section 2.7
of the Original Agreement, to read as follows:

     Borrower or Plains Marketing Canada, L.P., as the case may be, may request
     that any Canadian Letter of Credit be issued in Dollars or in Canadian
     Dollars, and, subject to the terms and conditions hereof, LC Issuer will
     honor such request.

                                                    LC/Hedged Inventory Facility

                                       8

     (S) 2.7.  Requesting Letters of Credit.  The references to "Borrower" set
forth in Section 2.8 of the Original Agreement are hereby amended to refer
instead to "Borrower or Plains Marketing Canada, L.P., as the case may be,".

     (S) 2.8.  Letter of Credit Reimbursement.  Section 2.9(a) of the Original
Agreement is hereby amended in its entirety to read as follows:

          (a)  Reimbursement.  Each Matured LC Obligation shall constitute a
     loan by LC Issuer to Borrower or Plains Marketing Canada, L.P., as the case
     may be.  Borrower promises to pay to LC Issuer, or to LC Issuer's order, on
     demand, the full amount of each Matured LC Obligation (which, in the case
     of any Letter of Credit issued in Canadian Dollars, shall as demanded by LC
     Issuer be payable in Canadian Dollars or in an amount equal to the
     equivalent in Dollars of such amount of Canadian Dollars determined by LC
     Issuer in accordance with its normal procedures and after deducting any
     premium and costs of exchange), including without limitation all Matured LC
     Obligations with respect to Canadian Letters of Credit issued at the
     request of Plains Marketing Canada, L.P., together with interest thereon
     (i) at the Base Rate to and including the second Business Day after the
     Matured LC Obligation is incurred and (ii) at the Default Rate on each day
     thereafter.  In addition, and notwithstanding the foregoing, Plains
     Marketing Canada, L.P., pursuant to each LC Application executed by it,
     shall be obligated to pay to LC Issuer, or to LC Issuer's order, on demand,
     the full amount of each Matured LC Obligation with respect to Canadian
     Letters of Credit requested by it (which, in the case of any Letter of
     Credit issued in Canadian Dollars, shall as demanded by LC Issuer be
     payable in Canadian Dollars or in an amount equal to the equivalent in
     Dollars of such amount of Canadian Dollars determined by LC Issuer in
     accordance with its normal procedures and after deducting any premium and
     costs of exchange), together with interest thereon as set forth in the
     foregoing sentence (such obligation and Borrower's obligation set forth in
     the foregoing sentence with respect to such Canadian Letters of Credit to
     be joint and several).  Any such reimbursement made by Plains Marketing
     Canada, L.P. shall, pursuant to Section 3.7(b) hereof, include all such
     additional amounts as are needed to cause the amount received by LC Issuer,
     after any deduction or withholding as may be required pursuant to the
     Income Tax Act (Canada) or other applicable Canadian Laws, to equal the
     amount which would have been receivable in the absence of such deduction or
     withholding.

     The references to "Borrower" set forth in the second sentence of Section
2.9(c) and in Section 2.9(d) of the Original Agreement are hereby amended to
refer instead to "Borrower or, with respect to Canadian Letters of Credit
requested by Plains Marketing Canada, L.P., by either Borrower or Plains
Marketing Canada, L.P.".

     (S) 2.9.  LC Collateral.  The reference to "outstanding LC Obligations" set
forth in the first sentence of Section 2.11(a) of the Original Agreement is
hereby amended to refer instead to "Dollar Equivalent of outstanding LC
Obligations".

                                                    LC/Hedged Inventory Facility

                                       9

     The reference to "aggregate LC Obligations" set forth in the last sentence
of Section 2.11(b) of the Original Agreement is hereby amended to refer instead
to "aggregate Dollar Equivalent of LC Obligations".

     (S) 2.10. Commitment Fee.  The references to "Facility Usage" set forth in
Section 2.12(b) of the Original Agreement are hereby amended to refer instead to
"Dollar Equivalent of the Facility Usage".

     (S) 2.11. Letter of Credit Fees.  Section 2.12(c) of the Original Agreement
is hereby amended in its entirety to read as follows:

          (c)  Letter of Credit Fees.  In consideration of LC Issuer's issuance
     of any Letter of Credit, Borrower agrees to pay (i) to Administrative
     Agent, for the account of all Lenders in accordance with their respective
     Percentage Shares, a letter of credit fee equal to the Letter of Credit Fee
     Rate applicable each day times the Dollar Equivalent of the face amount of
     such Letter of Credit and (ii) to such LC Issuer for its own account, a
     letter of credit fronting fee at a rate equal to one-eighth percent
     (0.125%) per annum times the Dollar Equivalent of the face amount of such
     Letter of Credit.  Each such fee will be calculated on the face amount of
     each Letter of Credit outstanding on each day at the above applicable rates
     and will be payable monthly in arrears on the last day of each month.  In
     addition, Borrower will pay to LC Issuer a minimum administrative issuance
     fee and such other fees and charges customarily charged by the LC Issuer in
     respect of any issuance, amendment or negotiation of any Letter of Credit
     in accordance with the LC Issuer's published schedule of such charges
     effective as of the date of such amendment or negotiation.  In addition, in
     the event any Canadian Letter of Credit shall at the request of Borrower or
     Plains Marketing Canada, L.P., as the case may be, be issued pursuant to an
     LC Issuer's Canadian office, Borrower will pay a minimum fee for such
     service as customarily charged by such LC Issuer.  In addition, and
     notwithstanding the foregoing, Plains Marketing Canada, L.P., pursuant to
     each LC Application executed by it, shall with respect to Canadian Letters
     of Credit requested by it agree to pay such letter of credit fees as set
     forth in this Section 2.12(c) (such obligation and Borrower's obligation
     set forth in this Section 2.12(c) with respect to such Canadian Letters of
     Credit to be joint and several).  Any such payment of letter of credit fees
     made by Plains Marketing Canada, L.P. shall, pursuant to Section 3.7(b)
     hereof, include all such additional amounts as are needed to cause the
     amount received by Administrative Agent and LC Issuer, in each case, after
     any deduction or withholding as may be required pursuant to the Income Tax
     Act (Canada) or other applicable Canadian Laws, to equal the amount which
     would have been receivable in the absence of such deduction or withholding.

     (S) 2.12. General Procedures - Payments.  The first sentence of Section 3.1
of the Original Agreement is hereby amended by adding the following
parenthetical phrase immediately following "lawful money of the United States of
America":

     (unless otherwise expressly provided in this Agreement)

                                                    LC/Hedged Inventory Facility

                                       10

     Section 3.1 of the Original Agreement is hereby further amended by adding
the following at the end thereof:

     If any payment on account of any Obligation is received in Canadian
     Dollars, instead of Dollars as required pursuant to this section (whether
     voluntarily or pursuant to an order or judgment or the enforcement thereof
     or the realization of any security or the liquidation of such Restricted
     Person or otherwise howsoever), such payment shall constitute a discharge
     of such Obligation only to the extent of the equivalent in Dollars of such
     amount of Canadian Dollars determined by Administrative Agent in accordance
     with its normal procedures and after deducting any premium and costs of
     exchange, determined as of the Business Day next following such receipt.
     If, for the purpose of obtaining or enforcing judgment in any court in any
     Canadian jurisdiction, it becomes necessary to convert any amount due in
     Dollars into Canadian Dollars, then the Dollar Equivalent of such amount
     shall be determined on the Business Day following the date such judgment is
     given, and in any event Restricted Persons shall continue to be obligated
     to pay any deficiency owing to any Lender Party.  If any Lender Party
     receives any payment or payments on account of the liability of any
     Restricted Person hereunder pursuant to any judgment or order in Canadian
     Dollars, and the Dollar Equivalent of such amount on the Business Day next
     following such receipt is less than the full amount of the Obligation due
     immediately prior to such judgment or order, then Borrower on demand shall
     indemnify and save such Lender Party harmless from and against any loss,
     cost or expense arising out of or in connection with such deficiency.  The
     agreement of indemnity provided for in this Section 3.1 shall constitute an
     obligation separate and independent from all other obligations contained in
     this Agreement, shall give rise to a separate and independent cause of
     action, shall apply irrespective of any indulgence granted by the Lender
     Parties or any of them from time to time, and shall continue in full force
     and effect notwithstanding any judgment or order for a liquidated sum in
     respect of an amount due hereunder or under any judgment or order.

     (S) 2.13. Notices and Environmental Matters.  The references to
"$1,000,000" set forth in Section 6.4(e), 6.12(b) and 6.12(c) of the Original
Agreement are hereby amended to refer instead to "the Dollar Equivalent of
$1,000,000".

     (S) 2.14. Indebtedness under Revolver Agreement and Issuance of Additional
Indebtedness.  The reference to "$400,000,000" set forth in Section 7.1(e) of
the Original Agreement is hereby amended to refer instead to "$630,000,000".

     Clause (g) of Section 7.1 of the Original Agreement is hereby redesignated
clause (h), and a new clause (g) is hereby added immediately before such clause
(h), to read as follows:

          (g) Indebtedness owing by Plains MLP or any other Restricted Person
     under its senior unsecured privately placed or public term Indebtedness
     (and any Indebtedness issued in exchange therefor), provided (1) such
     Indebtedness shall not permit optional redemption by the issuer or
     mandatory redemption by any holder thereof solely at the option of any such
     holder, nor any stated maturity, in each case prior to the Maturity

                                                    LC/Hedged Inventory Facility

                                       11

     Date, (2) the indenture governing such Indebtedness shall have no covenants
     or other requirements more onerous than the Loan Documents, (3) the
     aggregate outstanding face amount of such Indebtedness shall not exceed
     $400,000,000, (4) all of the net proceeds of such originally issued
     Indebtedness shall be used to repay loans to Borrower outstanding under the
     Revolver Agreement as therein provided, (5) upon the receipt of net
     proceeds from the original issuance of such Indebtedness, the Commitment
     (as defined in the Revolver Agreement) under the Revolver Agreement shall
     be permanently reduced (as provided in the Revolver Agreement) by an amount
     equal to (A) forty percent (40%) of the face amount of such Indebtedness,
     if the aggregate face amount is less than $350,000,000, or (B) fifty
     percent (50%) of the face amount of such Indebtedness, if the aggregate
     face amount of such bonds is equal to or greater than $350,000,000, and (6)
     both immediately prior to and immediately following the consummation of
     such offering, no Default or Event of Default shall have occurred and be
     continuing.

     The reference to "$25,000,000" set forth in Section 7.1(g) of the Original
Agreement (to be redesignated as clause (h) as set forth in the prior paragraph
hereof) is hereby amended to refer instead to "the Dollar Equivalent of
$25,000,000".

     (S) 2.15. Limitation on Sales of Property.  The reference to "$10,000,000"
set forth in Section 7.5(c) of the Original Agreement is hereby amended to refer
instead to "the Dollar Equivalent of $10,000,000".

     (S) 2.16. Debt Coverage Ratio.  Section 7.12 of the Original Agreement is
hereby amended in its entirety to read as follows:

          Section 7.12.  Debt Coverage Ratio.  (a) At the end of any Fiscal
     Quarter, (b) on any date on which General Partner declares a distribution
     permitted under Section 7.6 and (c) on the date of any Permitted
     Acquisition, both immediately prior to and after giving effect to the
     consummation thereof, the Debt Coverage Ratio will not be greater than:

               (i) prior to both the CanPet Acquisition Closing Date and Murphy
     Acquisition Closing Date: (A) 4.0 to 1.0, in the case of any determination
     during the period from the date hereof through and including March 31,
     2002, and (B) 3.75 to 1.0, in the case of any determination thereafter;

               (ii) on and after the CanPet Acquisition Closing Date, and prior
     to the Murphy Acquisition Closing Date (if the CanPet Acquisition Closing
     Date shall occur prior to the Murphy Acquisition Closing Date): (I) 4.25 to
     1.0, in the case of any determination during the period from the date
     hereof through and including December 30, 2002, and (II) 4.00 to 1.0, in
     the case of any determination thereafter; and

               (iii) on and after the Murphy Acquisition Closing Date (whether
     or not the CanPet Acquisition Closing Date has occurred): (A) 4.75 to 1.0,
     in the case of any determination during the period from the date hereof
     through and including

                                                    LC/Hedged Inventory Facility

                                       12

     September 29, 2001, (B) 4.50 to 1.0, in the case of any determination
     during the period from September 30, 2001 through and including June 29,
     2002, (C) 4.25 to 1.0, in the case of any determination from June 30, 2002
     through and including December 30, 2002, and (D) 4.00 to 1.0, in the case
     of any determination thereafter.

     As used herein, "Debt Coverage Ratio" means the ratio of (a) Consolidated
     Funded Indebtedness to (b) Consolidated EBITDA for the four Fiscal Quarter
     period (or other period specified below) most recently ended prior to the
     date of determination for which financial statements contemplated by
     Section 6.2(a) or (b) are available to Borrower; provided, for purposes of
     this Section 7.12, if, since the beginning of the four Fiscal Quarter
     period ending on the date for which Consolidated EBITDA is determined, any
     Restricted Person shall have made any asset disposition or acquisition,
     shall have consolidated or merged with or into any Person (other than
     another Restricted Person), or shall have made any disposition or
     acquisition of a Restricted Person, Consolidated EBITDA shall be calculated
     giving pro forma effect thereto as if the disposition, acquisition,
     consolidation or merger had occurred on the first day of such period. Such
     pro forma effect shall be determined (i) in good faith by the chief
     financial officer of Borrower, and (ii) without giving effect to any
     anticipated or proposed change in operations, revenues, expenses or other
     items included in the computation of Consolidated EBITDA, except with the
     consent of Majority Lenders.

     (S) 2.17. Debt to Capital Ratio.  Section 7.14 of the Original Agreement is
hereby amended in its entirety to read as follows:

          Section 7.14  Debt to Capital Ratio.  The ratio of (a) all
     Consolidated Funded Indebtedness to (b) the sum of Consolidated Funded
     Indebtedness plus Consolidated Net Worth will never be greater than:

               (i) prior to both the CanPet Acquisition Closing Date and the
     Murphy Acquisition Closing Date: 0.65 to 1.0 at any time;

               (ii) on and after the CanPet Acquisition Closing Date, and prior
     to the Murphy Acquisition Closing Date (if the CanPet Acquisition Closing
     Date shall occur prior to the Murphy Acquisition Closing Date): 0.67 to 1.0
     at any time prior to December 30, 2002, and 0.65 to 1.0 thereafter; and

               (iii) on and after the Murphy Acquisition Closing Date (whether
          or not the CanPet Acquisition Closing Date has occurred): 0.73 to 1.0
          at any time prior to December 30, 2002, and 0.65 to 1.0 thereafter.

     (S) 2.18. Events of Default.  The references to "$2,500,000" set forth in
Section 8.1(g), 8.1(i)(iv), 8.1(i)(v) and 8.1(i)(vi) of the Original Agreement
are hereby amended to refer instead to "the Dollar Equivalent of $2,500,000".

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                                       13

     (S) 2.19. Lender Schedule.  The Composite Lender Schedule set forth on the
last page of the Lender Schedule attached as Schedule 1 to the Original
Agreement is hereby amended in its entirety to read as set forth on the
Composite Lender Schedule attached hereto.

     (S) 2.20. Schedules and Exhibits.  Schedule 3 and Exhibits A and H attached
to the Original Agreement are hereby amended in their respective entirety to
read as set forth on Schedule 3 and Exhibits A and H attached hereto.

     (S) 2.21. Consent to Transfers and Issuances of Limited Partner Interests
in Plains Marketing Canada, L.P.  As of the date hereof, Plains Marketing Canada
LLC, a Delaware limited liability company, owns all of the outstanding limited
partner interests in Plains Marketing Canada, L.P., an Alberta limited
partnership.  Lenders hereby consent to the transfer by Plains Marketing Canada
LLC, a Delaware limited liability company, of any or all such outstanding
limited partner interests in Plains Marketing Canada, L.P. to Borrower, and
waive any Default or Event of Default under Section 7.4(b) or Section 7.7 of the
Credit Agreement caused thereby.

     As of the date hereof, all of the outstanding limited partner interests in
Plains Marketing Canada, L.P., an Alberta limited partnership, are owned,
directly or indirectly, by Borrower. Lenders hereby consent to the issuance by
Plains Marketing Canada, L.P., an Alberta limited partnership, of limited
partner interests to CanPet Energy Group (USA), Inc. or CanPet Energy Group Inc.
to effect the consummation of the CanPet Acquisition as set forth in the CanPet
Acquisition Documents, and waive any Default or Event of Default under Section
7.4 or Section 7.6 of the Credit Agreement caused thereby, provided, such
limited partner interests shall:

          (i) pay no cash dividend nor entitle the holder thereof to any cash
     distribution, except upon dissolution (provided that the foregoing shall
     not prevent the accrual of any such dividends or distributions);

          (ii) not entitle the holder thereof to any right to manage or control
     Plains Marketing Canada, L.P. or vote with respect thereto; and

          (iii)  not be redeemable or exchangeable by the holder thereof for
     cash or callable or subject to a put option for cash at the option of any
     such holder.

     In the event any limited partner interests issued by Plains Marketing
Canada, L.P., an Alberta limited partnership, to CanPet Energy Group (USA), Inc.
or CanPet Energy Group Inc. are exchanged for units issued by Plains MLP,
Lenders hereby consent to the contribution by Plains MLP to Borrower of any and
all such partnership interests, and waive any Default or Event of Default under
Section 7.4(c) or Section 7.5 of the Credit Agreement caused thereby.

     (S) 2.22. Consent to CanPet Acquisition.  Lenders hereby consent to the
CanPet Acquisition (as defined in the Credit Agreement as amended hereby),
subject to the following:

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                                       14

          (a) Administrative Agent shall have received and approved copies of
     all environmental evaluations, reports or reviews related to properties to
     be acquired pursuant to the CanPet Acquisition, and there shall be no
     existing or potential environmental liabilities disclosed thereunder or
     otherwise existing except as disclosed by Borrower to Administrative Agent
     and Lenders prior to the date hereof.

          (b) Administrative Agent and each Lender shall have received any
     updated or revised business and/or financial projections with respect to
     the assets and operations to be acquired pursuant to the CanPet
     Acquisition, and no such projection shall materially and adversely differ
     from those projections previously delivered to Administrative Agent and
     Lenders.

          (c) The CanPet Acquisition shall exclude the acquisition of any
     existing or potential environmental or litigation liabilities incurred
     prior to the CanPet Acquisition Closing Date, except as disclosed by
     Borrower to Administrative Agent and Lenders prior to the date hereof, and
     Borrower and Plains Marketing Canada, L.P., as acquirers, shall have
     received an environmental indemnity providing for a deductible of not more
     than C$50,000 in the aggregate (not applicable with respect to
     environmental liabilities disclosed to Administrative Agent and Lenders
     prior to the date hereof) and a cap of not less than C$3,000,000 in the
     aggregate, to be effective for not less than two years with respect to on-
     site contamination and three years with respect to off-site contamination
     following the CanPet Acquisition Closing Date, and otherwise reasonably
     satisfactory to Administrative Agent with respect to such liabilities.

          (d) Administrative Agent  shall have received and approved copies of
     all CanPet Acquisition Documents and all other related documents as
     Administrative Agent may request.

          (e) The cash portion of the purchase price shall not exceed
     $26,000,000.

          (f) Both immediately prior to and immediately following the
     consummation of the CanPet Acquisition, no Material Adverse Change shall
     have occurred since December 31, 1999, and no Default or Event of Default
     shall have occurred and be continuing.

          (g) Canadian Subsidiaries shall have delivered Security Documents
     pursuant to Section 6.14 of the Credit Agreement with respect to the
     properties acquired pursuant to the CanPet Acquisition, the definition of
     "Marketing Credit Priority Collateral" set forth in the Intercreditor
     Agreement dated May 8, 2000 among the Administrative Agent, Lenders and the
     administrative agent and lenders under the Marketing Credit Agreement shall
     be amended to include properties of the type described therein owned by
     Canadian Subsidiaries as well as Borrower, and pursuant thereto such Liens
     on all other such Canadian Subsidiaries' property securing the Obligations
     shall be subordinated to the Liens on such Canadian Subsidiaries' property
     securing the Indebtedness under the Revolver Agreement.

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                                       15

     (S) 2.23. Consent to Murphy Acquisition.  Lenders hereby consent to the
Murphy Acquisition, subject to the following:

          (a) Administrative Agent shall have received and approved copies of
     all environmental evaluations, reports or reviews related to properties to
     be acquired pursuant to the Murphy Acquisition, and there shall be no
     existing or potential environmental liabilities disclosed thereunder or
     otherwise existing except as disclosed by Borrower to Administrative Agent
     and Lenders prior to the date hereof.

          (b) Administrative Agent and each Lender shall have received any
     updated or revised business and/or financial projections with respect to
     the assets and operations to be acquired pursuant to the Murphy
     Acquisition, and no such projection shall materially and adversely differ
     from those projections previously delivered to Administrative Agent and
     Lenders.

          (c) The Murphy Acquisition shall exclude the acquisition of any
     existing or potential environmental or litigation liabilities incurred
     prior to the Murphy Acquisition Closing Date, except as disclosed by
     Borrower to Administrative Agent and Lenders prior to the date hereof, and
     Plains Marketing Canada, L.P., as acquirer, shall have received an
     environmental indemnity with respect to all environmental liabilities
     disclosed to Administrative Agent and Lenders prior to the date hereof and
     further providing for a deductible of not more than $300,000 in the
     aggregate, with a $20,000 deductible per site thereafter, and a cap of not
     less than $3,000,000 in the aggregate, with respect to all other
     environmental liabilities, and otherwise reasonably satisfactory to
     Administrative Agent with respect to such liabilities.

          (d) Administrative Agent  shall have received and approved copies of
     all Murphy Acquisition Documents and all other related documents as
     Administrative Agent may request.

          (e) The cash portion of the purchase price shall not exceed
     $155,000,000 (subject to upward adjustment for net working capital
     adjustments not to exceed $6,000,000 in the aggregate).

          (f) Both immediately prior to and immediately following the
     consummation of the Murphy Acquisition, no Material Adverse Change shall
     have occurred since December 31, 1999, and no Default or Event of Default
     shall have occurred and be continuing.

          (g) On the Murphy Acquisition Closing Date: (1) Canadian Subsidiaries
     shall on the Murphy Acquisition Closing Date deliver Security Documents
     pursuant to Section 6.14 of the Credit Agreement (together with opinions of
     legal counsel for Canadian Subsidiaries and related corporate documents and
     records; documents evidencing governmental authorizations, consents,
     approvals, licenses and exemptions; and certificates of public officials
     and of officers and representatives of Restricted Persons as

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                                       16

     Administrative Agent may request) with respect to all of their properties,
     and (2) the Intercreditor Agreement dated May 8, 2000 among the
     Administrative Agent, Lenders and the administrative agent and lenders
     under the Marketing Credit Agreement shall be amended and restated to,
     among other things, amend the definition of "Marketing Credit Priority
     Collateral" to include properties of the type described therein owned by
     Canadian Subsidiaries as well as Borrower, and pursuant thereto such Liens
     on all other such Canadian Subsidiaries' property securing the Obligations
     shall be subordinated to the Liens on such Canadian Subsidiaries' property
     securing the Indebtedness under the Revolver Agreement.

     (S) 2.24. Consent to Restated Agreement.  Lenders hereby consent to the
addition to the Revolver Agreement of a $100,000,000 term loan facility to PMC
(Nova Scotia) Company, a Nova Scotia unlimited liability company and a Canadian
Subsidiary, and $30,000,000 Canadian working capital revolving credit facility
to PMC (Nova Scotia) Company, a Nova Scotia unlimited liability company, or
Plains Marketing Canada, L.P., an Alberta limited partnership, or both of them
if applicable, to be funded in connection with the consummation of the Murphy
Acquisition, pursuant to the terms and conditions set forth on the indicative
term sheet attached hereto as Annex I, and to permit the extensions of credit
from time to time outstanding thereunder and the accrued interest and fees in
respect thereof and currency Hedging Contracts executed in connection with the
funding thereof to share ratably in the benefits of the Revolver Agreement and
the other "Loan Documents" (as defined in the Revolver Agreement) with the loans
and letter of credit obligations thereunder and the accrued interest and fees in
respect thereof and pari passu with respect to all Collateral thereunder.

     In furtherance of the foregoing, each Lender hereby acknowledges and agrees
that it shall, subject to reasonable documentation review and approval of
Majority Lenders, execute and deliver (a) an amended and restated credit
agreement, amending and restating the Credit Agreement, contemporaneous with the
execution and delivery of an amended and restated credit agreement adding such
facilities to the Revolver Agreement, and (b) an amended and restated
intercreditor agreement among all lenders under the Credit Agreement, as so
amended and restated, and under the Revolver Agreement, providing for, among
other things, an amendment to the definition of "Marketing Credit Priority
Collateral" in the existing Intercreditor Agreement to include properties of the
type described therein owned by Canadian Subsidiaries as well as Borrower, and
pursuant thereto Liens on such "Marketing Credit Priority Collateral" securing
the Indebtedness under the Revolver Agreement shall be subordinated to the Liens
on such "Marketing Credit Priority Collateral" securing the Obligations, and
Liens on all other property securing the Obligations shall be subordinated to
the Liens on such other property securing the Indebtedness under the Revolver
Agreement.  In consideration of each Lender's execution and delivery of this
Agreement and such Lender's agreement to execute and deliver such amended and
restated credit agreement and intercreditor agreement, Borrower hereby agrees to
pay to Administrative Agent for the account of each Lender the amendment fees
and/or work fees set forth in that certain letter of even date herewith between
Borrower and Administrative Agent, on behalf of Lenders.

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                  ARTICLE III. -- Conditions of Effectiveness

     (S) 3.1.  Effective Date.  This Amendment shall become effective as of the
date first above written when, and only when:

     (a) Administrative Agent shall have received, at Administrative Agent's
office, a counterpart of this Amendment executed and delivered by Borrower and
Majority Lenders (and with respect to Sections 2.1(d), (g), (h) and (o), all
Lenders), and consented to by each Guarantor;

     (b) Borrower shall have issued and delivered to Administrative Agent, for
subsequent delivery to each Lender, a Renewal Note with appropriate insertions
payable to the order of such Lender, duly executed on behalf of Borrower, dated
the date hereof,

     (c) Restricted Persons shall have executed and delivered to Administrative
Agent Amendments to Security Documents amending the description of the secured
indebtedness therein to reflect the issuance of the Renewal Notes;

     (d) Administrative Agent shall have received all fees required to be paid
to Administrative Agent or any Lender pursuant to any Loan Documents, including
fees and expenses of Thompson & Knight LLP, counsel to Administrative Agent; and

     (e) Administrative Agent shall have additionally received all of the
following documents, each document (unless otherwise indicated) being dated the
date of receipt thereof by Administrative Agent, duly authorized, executed and
delivered, and in form and substance satisfactory to Administrative Agent:

          (i) Revolver Amendment.  A contemporaneous amendment to the Revolver
     Agreement, increasing the Revolver Commitment to $500,000,000 and
     consenting to the future addition of an additional $100,000,000 term loan
     and a $30,000,000 working capital revolver as described in Section 2.23,
     consenting to the CanPet Acquisition and the Murphy Acquisition on the same
     terms and conditions set forth herein, amending certain financial covenants
     on the same terms and conditions set forth herein, and amending various
     other provisions therein consistent with the amendments set forth herein;

          (ii) Opinions of Counsel for Restricted Persons.  The written opinions
     of Fulbright & Jaworski, L.L.P., special Texas and New York counsel to
     Restricted Persons, and an opinion of Tim Moore, General Counsel for
     Restricted Persons, addressed to Administrative Agent and Lenders, to the
     effect that this Amendment, each Renewal Note and the other Amendment
     Documents have been duly authorized, executed and delivered by Restricted
     Persons, to the extent a party thereto, and that the Credit Agreement, each
     Renewal Note and the other Amendment Documents constitute the legal, valid
     and binding obligations of Restricted Persons, to the extent a party
     thereto, enforceable in accordance with their respective terms (subject, as
     to enforcement of remedies, to

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                                       18

     applicable bankruptcy, reorganization, insolvency and similar laws and to
     moratorium laws and other laws affecting creditors' rights generally from
     time to time in effect).

          (iii)  Officer's Certificate.  A certificate of a duly authorized
     officer of General Partner stating that all of the representations and
     warranties set forth in Article IV hereof are true and correct at and as of
     the time of such effectiveness.

          (iv)  Supporting Documents.  (I) A Certificate of the Secretary of
     General Partner dated the date of this Amendment certifying that attached
     thereto is a true and complete copy of resolutions adopted by the Board of
     Directors of General Partner authorizing the execution, delivery and
     performance of this Amendment, each Renewal Note and the other Amendment
     Documents by Restricted Persons and certifying the names and true
     signatures of the officers of General Partner authorized to sign this
     Amendment, each Renewal Note and the other Amendment Documents on behalf of
     Restricted Persons, and (II) such supporting documents as Administrative
     Agent may request.

                 ARTICLE IV. -- Representations and Warranties

     (S) 4.1.  Representations and Warranties of Plains MLP and Borrower.  In
order to induce Administrative Agent and Lenders to enter into this Amendment,
Plains MLP and Borrower represent and warrant to Administrative Agent and each
Lender that:

          (a) The representations and warranties contained in Article V of the
     Original Agreement are true and correct at and as of the time of the
     effectiveness hereof, except to the extent that such representation and
     warranty was made as of a specific date.

          (b) Each Restricted Person is duly authorized to execute and deliver
     this Amendment, each Renewal Note and each other Amendment Document, to the
     extent a party thereto, and Borrower is and will continue to be duly
     authorized to borrow and perform its obligations under the Credit
     Agreement.  Each Restricted Person has duly taken all action necessary to
     authorize the execution and delivery of this Amendment, each Renewal Note
     and each other Amendment Document, to the extent a party thereto, and to
     authorize the performance of their respective obligations hereunder.

          (c) The execution and delivery by each Restricted Person of this
     Amendment, each Renewal note and each other Amendment Document, to the
     extent a party thereto, the performance by each Restricted Person of its
     respective obligations hereunder and thereunder, and the consummation of
     the transactions contemplated hereby and thereby, do not and will not
     conflict with any provision of any Law or of the organizational documents
     of any Restricted Person, or of any material agreement, judgment, license,
     order or permit applicable to or binding upon any Restricted Person, or
     result in the creation of any Lien upon any assets or properties of any
     Restricted Person, except in favor of Administrative Agent for the benefit
     of Lenders and other Permitted Liens. Except for those which have been duly
     obtained, no consent, approval, authorization or order of any Tribunal or
     third party is required in connection with the execution and

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                                       19

     delivery by any Restricted Person of this Amendment, any Renewal Note or
     any other Amendment Document, or to consummate the transactions
     contemplated hereby and thereby.

          (d) When duly executed and delivered, each of this Amendment, each
     Renewal Note, each other Amendment Document, and each of the Loan
     Documents, as amended hereby and thereby, will be a legal and binding
     instrument and agreement of each Restricted Person to the extent a party
     thereto, enforceable in accordance with its terms, (subject, as to
     enforcement of remedies, to applicable bankruptcy, insolvency and similar
     laws applicable to creditors' rights generally).

          (e) The business and financial projections with respect to the assets
     and operations to be acquired pursuant to the CanPet Acquisition and the
     Murphy Acquisition previously delivered to Administrative Agent and Lenders
     fairly present Restricted Persons' best projections with respect thereto,
     and are based on reasonable historical business assumptions with respect to
     such assets and operations as well as Restricted Persons' current business
     operations and financial performance.  No Material Adverse Change has
     occurred since December 31, 1999.

                          ARTICLE V. -- Miscellaneous

     (S) 5.1.  Ratification of Agreements.  The Original Agreement, as hereby
amended, is hereby ratified and confirmed in all respects.  The Loan Documents
(including but not limited to each Guaranty), as they may be amended or affected
by this Amendment or any other Amendment Document, are hereby ratified and
confirmed in all respects by each Restricted Person to the extent a party
thereto.  Any reference to the Credit Agreement in any Loan Document shall be
deemed to refer to this Amendment also.  Any reference to the Notes in any other
Loan Document shall be deemed to be a reference to the Renewal Notes issued and
delivered pursuant to this Amendment.   The execution, delivery and
effectiveness of this Amendment, the Renewal Notes and the other Amendment
Documents shall not, except as expressly provided herein, operate as a waiver of
any right, power or remedy of Administrative Agent or any Lender under the
Credit Agreement or any other Loan Document nor constitute a waiver of any
provision of the Credit Agreement or any other Loan Document.

     (S) 5.2.  Ratification of Security Documents.  Restricted Persons,
Administrative Agent, and Lenders each acknowledge and agree that any and all
indebtedness, liabilities or obligations arising under or in connection with the
LC Obligations, as amended hereby, or the Notes, as amended hereby, are
Obligations and are secured indebtedness under, are guarantied by, and are
secured by, each and every Security Document to which any Restricted Person is a
party.  Each Restricted Person hereby re-pledges, re-grants and re-assigns a
security interest in and lien on every asset of the such Restricted Person
described as Collateral in any Security Document and re-guarantees all
Obligations, as amended hereby.

     (S) 5.3.  Ratification of Intercreditor Agreement.  Each Lender hereby
acknowledges and confirms that all Obligations under the Credit Agreement, as
amended hereby, and the

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                                       20

"Obligations" under the Revolver Agreement, as amended on the date hereof, shall
be and shall remain subject to the terms and entitled to the benefits of the
Intercreditor Agreement.

     (S) 5.4.  Survival of Agreements.  All representations, warranties,
covenants and agreements of the Restricted Persons herein shall survive the
execution and delivery of this Amendment and the performance hereof, including
without limitation the making or granting of each Loan and the issuance and
delivery of the Renewal Notes, and shall further survive until all of the
Obligations are paid in full.  All statements and agreements contained in any
certificate or instrument delivered by any Restricted Person hereunder or under
the Credit Agreement to Administrative Agent or any Lender shall be deemed to
constitute representations and warranties by, or agreements and covenants of,
such Restricted Person under this Amendment and under the Credit Agreement.

     (S) 5.5.  Loan Documents.  This Amendment, each Renewal Note, and each
other Amendment Document is a Loan Document, and all provisions in the Credit
Agreement pertaining to Loan Documents apply hereto.

     (S) 5.6.  GOVERNING LAW.  THIS AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED
IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND ANY APPLICABLE LAWS OF
THE UNITED STATES OF AMERICA IN ALL RESPECTS, INCLUDING CONSTRUCTION, VALIDITY
AND PERFORMANCE.

     (S) 5.7.  Counterparts.  This Amendment may be separately executed in
counterparts and by the different parties hereto in separate counterparts, each
of which when so executed shall be deemed to constitute one and the same
Amendment.

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                                       21

     IN WITNESS WHEREOF, this Amendment is executed as of the date first above
written.

                              PLAINS MARKETING, L.P.

                              By:   PLAINS ALL AMERICAN INC.,
                                    its general partner

                                    By:
                                        --------------------------
                                        Phil Kramer
                                        Executive Vice President

                              PLAINS ALL AMERICAN PIPELINE, L.P.

                              By:   PLAINS ALL AMERICAN INC.,
                                    its general partner

                                    By:   /s/ Phil Kramer
                                        --------------------------
                                        Phil Kramer
                                        Executive Vice President

                              ALL AMERICAN PIPELINE, L.P.

                              By:   PLAINS ALL AMERICAN INC.,
                                    its general partner

                                    By:   /s/ Phil Kramer
                                        --------------------------
                                        Phil Kramer
                                        Executive Vice President

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                                       22

                                    FLEET NATIONAL BANK,
                                     as Administrative Agent and Lender

                                    By:   /s/ Terrence Ronan
                                        --------------------------
                                        Terrence Ronan, Managing Director

                                    FIRST UNION NATIONAL BANK, Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    BANK OF AMERICA, N.A., Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    BANK ONE, NA (MAIN OFFICE
                                    CHICAGO), successor by merger to Bank
                                    One, Texas, N.A., Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    BNP PARIBAS, Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    FORTIS CAPITAL CORP., Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

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                                       23

                                    U.S. BANK NATIONAL ASSOCIATION,
                                    Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    BANK OF SCOTLAND, Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    WELLS FARGO BANK (TEXAS),
                                    NATIONAL ASSOCIATION, Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    SIEMENS FINANCIAL SERVICES, INC.,
                                    Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    THE BANK OF NOVA SCOTIA, Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    CREDIT AGRICOLE INDOSUEZ, Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                                    LC/Hedged Inventory Facility

                                       24

                                    GUARANTY FEDERAL BANK, F.S.B.,
                                    Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    TORONTO DOMINION (TEXAS), INC.,
                                    Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    SOUTHWEST BANK OF TEXAS, N.A.,
                                    Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    UNION BANK OF CALIFORNIA, Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                    COMERICA BANK-TEXAS, Lender

                                    By:   /s/
                                        --------------------------
                                        Name:
                                        Title:

                                                    LC/Hedged Inventory Facility

                                       25

                             CONSENT AND AGREEMENT

     Each of the undersigned Guarantors hereby consents to the provisions of
this Amendment and the execution and delivery of the Renewal Notes and the other
Amendment Documents, and the transactions contemplated herein and therein and
hereby and thereby (i) acknowledges and agrees that any and all indebtedness,
liabilities or obligations arising under or in connection with the Renewal Notes
are Obligations and are secured indebtedness under, and are secured by, each and
every Security Document to which it is a party, (ii) re-pledges, re-grants and
re-assigns a security interest in and lien on all of its assets described as
collateral in any Security Document, (iii) ratifies and confirms its Guaranty
made by it for the benefit of Administrative Agent and Lenders, and (iv)
expressly acknowledges and agrees that such Guarantor guarantees all
indebtedness, liabilities and obligations arising under or in connection with
the Renewal Notes pursuant to the terms of such Guaranty, and agrees that its
obligations and covenants thereunder are unimpaired hereby and shall remain in
full force and effect.

                         PLAINS MARKETING CANADA LLC

                         By:  Plains Marketing, L.P., its sole member

                              By:   Plains All American Inc.,
                                    its general partner

                                    By:   /s/ Phil Kramer
                                       ---------------------------------
                                       Phil Kramer, Exec. Vice President

                         PMC (NOVA SCOTIA) COMPANY

                         By:   /s/ Phil Kramer
                            ---------------------------------
                            Phil Kramer, Exec. Vice President

                         PLAINS MARKETING CANADA, L.P.

                         By:  PMC (Nova Scotia) Company,
                              its general partner

                              By:   /s/ Phil Kramer
                                 ---------------------------------
                                 Phil Kramer, Exec. Vice President

                                                    LC/Hedged Inventory Facility

                                       26

                                                                    Exhibit 21.1

               Subsidiaries of Plains All American Pipeline, L.P.

Name                                         Jurisdiction
- ----                                         ------------
PAA Finance Corp.                            Delaware
Plains Marketing, L.P.                       Delaware
All American Pipeline, L.P.                  Texas
Plains Marketing Canada LLC                  Delaware
Plains Marketing Canada, L.P.                Canada
PMC (Nova Scotia) Company                    Canada

                                                                    Exhibit 23.1

                       CONSENT OF INDEPENDENT ACCOUNTANTS

   We hereby consent to the incorporation by reference in the Registration
Statement on Form S-8 (File Nos. 333-91141 and 333-54118) of Plains All American
Pipeline, L.P. of our reports dated March 22, 2001, relating to the consolidated
financial statements, which appear in this Form 10-K.

PricewaterhouseCoopers LLP

Houston, Texas
April 2, 2001