<PAGE>

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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: 0-9808

                             PLAINS RESOURCES INC.

             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

          DELAWARE                                    13-2898764
(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(g) OF THE ACT:

           Title of each class         Name of each exchange on which registered
           -------------------         -----------------------------------------
Common Stock, par value $0.10 per share         American 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 [ ]

On March 22, 2001, there were 17,462,320 shares of the registrant's Common Stock
outstanding. The aggregate value of the Common Stock 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 $358,500,547 on March 22, 2001 (based on $21 1/4 per share, the
last sale price of the Common Stock as reported on the American Stock Exchange
Composite Tape on such date).

DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the
Annual Report on Form 10-K is incorporated by reference to the Registrant's
definitive proxy statement to be filed pursuant to Regulation 14A for the
Registrant's Annual Meeting of Stockholders.

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]

================================================================================
<PAGE>

                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                          2000 FORM 10-K ANNUAL REPORT
                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                            PAGE
                                                                            ----
<S>         <C>                                                               <C>
                                          PART I
Item 1.      Business.......................................................    4
Item 2.      Properties.....................................................   31
Item 3.      Legal Proceedings..............................................   34
Item 4.      Submission of Matters to a Vote of Security Holders............   35

                                         PART II

Item 5.       Market for Registrant's Common Stock and Related Stockholder
               Matters......................................................   37
Item 6.       Selected Financial Data.......................................   38
Item 7.       Management's Discussion and Analysis of Financial Condition
               and Results of Operations....................................   40
Item 7a.      Quantitative and Qualitative - Disclosures About Market Risks.   54
Item 8.       Financial Statements and Supplementary Data...................   55
Item 9.       Changes in and Disagreements with Accountants on Accounting
               and Financial Disclosure.....................................   55

                                        PART III

Item 10.      Directors and Executive Officers..............................   56
Item 11.      Executive Compensation........................................   56
Item 12.      Security Ownership of Certain Beneficial Owners and Management   56
Item 13.      Certain Relationships and Related Transactions................   56

                                        PART IV

Item 14.      Exhibits, Financial Statement Schedules and Reports on
               Form 8-K.....................................................   57
</TABLE>

                                       2
<PAGE>

                           FORWARD-LOOKING STATEMENTS

  This annual report on Form 10-K contains forward-looking statements and
information that are based on our beliefs, as well as assumptions made by us,
and information currently available to us. All statements included in this
report, other than statements of historical fact, 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. Such
statements reflect our current views 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:

 .  uncertainties inherent in the exploration for and development and production
   of oil and gas and in estimating reserves;

 .  unexpected future capital expenditures (including the amount and nature
   thereof);

 .  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 availability of adequate supplies of and demand for crude oil in areas of
   midstream operations;

 .  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 those in
the forward-looking statements. Except as required by applicable securities
laws, we do not intend to update these forward-looking statements and
information.

                        DEFINITIONS OF OIL AND GAS TERMS

  As used in this report, "Bbl" means barrel, "MBbl" means thousand barrels,
"MMBbl" means million barrels, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "Btu" means British Thermal
Unit, "Mbtu" means thousand Btus, "BOE" means net barrel of oil equivalent and
"MCFE" means Mcf of natural gas equivalent. Natural gas equivalents and crude
oil equivalents are determined using the ratio of six Mcf of natural gas to one
Bbl of crude oil, condensate or natural gas liquids. A "working interest" is a
cost-bearing interest under an oil and gas lease that gives the holder the right
to produce and develop the minerals under the lease. A "net revenue interest" is
the lessee's share of production after satisfaction of all royalty and other non
cost-bearing interests. A "gross acre" is an acre in which an interest is owned.
The number of "net acres" is the sum of the fractional working interests owned
in gross acres. "Net" oil and natural gas wells are obtained by multiplying
"gross" oil and natural gas wells by our working interest in the applicable
properties. "Present Value of Proved Reserves" means the present value
(discounted at 10%) of estimated future cash flows from proved oil and natural
gas reserves, as estimated by our independent engineers, reduced by additional
estimated future operating expenses, development expenditures and abandonment
costs (net of salvage value) associated therewith (before income taxes). The
present value of proved reserves is calculated using product prices in effect on
the date of determination. "Standardized Measure" is such amount further reduced
by the present value (discounted at 10%) of estimated future income taxes on
such cash flows. "NYMEX" means New York Mercantile Exchange.

                                       3
<PAGE>

                                     PART I

ITEMS 1.  BUSINESS

General

  We are an independent energy company that is engaged in two related lines of
business. Our first line of business, which we refer to as "upstream", acquires,
exploits, develops, explores and produces crude oil and natural gas. Our second
line of business, which we refer to as "midstream", is engaged in the 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". We conduct
this second line of business through our majority ownership in Plains All
American Pipeline, L.P. ("PAA").

  One of our wholly owned subsidiaries, Plains All American Inc., is both the
general partner and majority owner of PAA. Because it holds the general partner
interest and owns approximately 18.1 million common and subordinated units,
Plains All American Inc. holds an approximate 54% interest in PAA. For financial
statement purposes, the assets, liabilities and earnings of PAA are included in
our consolidated financial statements, with the public unitholders' interest
reflected as a minority interest. The following chart sets forth the
organization relationship of the subsidiaries in our two lines of business:

                            [ORGANIZATIONAL CHART]

  In connection with our business strategy, we continually review strategic
options or proposals relating to mergers, consolidations and acquisition
opportunities involving us and our subsidiaries. We have publicly announced that
we are evaluating strategic restructuring alternatives intended to optimize the
value and value-creating ability of each of our upstream and midstream business
segments. The alternatives to be evaluated 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 units of PAA 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.

                                       4
<PAGE>

RESULTS OF OPERATIONS

  For the year ended December 31, 2000, our Adjusted EBITDA, cash flow from
operations and net income totaled $179.2 million, $100.6 million and $40.8
million, respectively. Adjusted EBITDA means earnings before interest expense,
income taxes, depreciation, depletion and amortization ("DD&A"), unauthorized
trading losses, noncash compensation expense, gain on unit offerings, gain on
sales of linefill and pipeline, allowance for accounts receivable, extraordinary
loss from extinguishment of debt and cumulative effect of accounting change.
Cash flow from operations represents net income before noncash items. Cash flow
from operations also excludes the unauthorized trading losses, noncash
compensation expense, gain on unit offerings, gain on sale of linefill and
pipeline, extraordinary loss from extinguishment of debt and cumulative effect
of accounting change. Our upstream operations contributed approximately 43% of
our Adjusted EBITDA for the fiscal year ending December 31, 2000, while our
midstream activities accounted for approximately 57%.

UPSTREAM ACTIVITIES

  Our upstream business strategy is to increase our proved reserves and cash
flow by:

 .  exploiting and producing crude oil and associated natural gas from our
   existing properties;

 .  acquiring additional underdeveloped crude oil properties; and

 .  exploring for significant new sources of reserves.

   We concentrate our acquisition and exploitation efforts on mature but
underdeveloped crude oil producing properties that meet our targeted criteria.
Generally, the properties that we consider acquiring and exploiting consist of
entire fields where major integrated or large independent oil and natural gas
companies own 100% or the controlling interest. Typically these fields have
produced significant volumes since initial discovery, exhibit complex reservoir
and geologic conditions and as a result thereof, are likely to have significant
estimated remaining reserves in place. Our management believes that it has
developed a proven record in acquiring and exploiting underdeveloped crude oil
properties where we can make substantial reserve additions and cash flow
increases by implementing improved production practices and recovery techniques
and by relatively low risk development drilling. An integral component of our
exploitation effort is to increase unit operating margins, and therefore cash
flow, by reducing unit production expenses and increasing wellhead price
realizations.

  We seek to complement these efforts by committing a minor portion of our
capital to pursue higher risk exploration opportunities that offer potentially
higher rewards in areas synergistic to our acquisition and exploitation
activities. As part of our business strategy, we periodically evaluate selling,
and from time to time have sold, certain of our mature producing properties that
we consider to be non-strategic or fully valued. These sales enable us to focus
on our core properties, maintain our financial flexibility, control our overhead
and re-deploy the sales proceeds to activities that have potentially higher
financial returns. We are able to take advantage of the marketing expertise that
PAA has developed through our marketing agreement under which they are exclusive
purchaser/marketer of all our equity crude oil production.

  During the five-year period ended December 31, 2000, we incurred aggregate
acquisition, exploitation, development, and exploration costs of approximately
$433.5 million, resulting in proved crude oil and natural gas reserve additions
(including revisions of estimates but excluding production) of approximately 179
million BOE, or $2.42 per BOE, through implementation of this business strategy.
We spent approximately 98% of this capital in acquisition, exploitation and
development activities and the remainder on our exploration activities.

  To manage our exposure to commodity price risk, our upstream business
routinely hedges a portion of its crude oil production. For 2001 and 2002, we
have entered into various arrangements, using a combination of swaps, collars
and purchased puts and calls. Our management intends to continue to maintain
hedging
                                       5
<PAGE>

arrangements for a significant portion of our production. See Item - 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Outlook" and Item 7a. - "Quantitative and Qualitative Disclosures
about Market Risks".

  The following table sets forth certain information with respect to our
reserves over the last five years. Our reserve volumes and values were
determined under the method prescribed by the Securities and Exchange Commission
("SEC"), which requires the application of year-end crude oil and natural gas
prices for each year, held constant throughout the projected reserve life.

<TABLE>
<CAPTION>
                                                                  As of or for the Year Ended December 31,
                                                   ---------------------------------------------------------------------------
                                                       2000             1999           1998            1997           1996
                                                   -------------    -------------   ------------    -----------    -----------
                                                              (in thousands, except ratios and per unit amounts)
<S>                                                 <C>             <C>           <C>               <C>              <C>
Present Value of Proved Reserves /(1)/              $1,345,392      $1,246,049    $  226,943        $  510,993       $  764,774

Proved Reserves
    Crude oil and natural gas liquids (Bbls)           223,162/(2)/    218,922       120,208           151,627          115,996
    Natural gas (Mcf)                                   93,486          90,873        86,781            60,350           37,273
    Oil equivalent (BOE)                               238,743         234,068       134,672           161,685          122,208

Reserve Replacement Ratio /(3)/                            153%          1,263%         (229%)/(4)/        603%/(5)         454%

Reserve Replacement Cost per BOE /(6)/              $     5.98      $     0.68    $    (5.46)/(4)/  $     2.71       $     1.76

Total upstream capital costs incurred               $   80,928      $   72,979    $  100,935        $  127,378       $   51,255
Percentage of total upstream capital
costs attributable to:
    Acquisition                                              3%              5%           10%               34%               7%
    Development                                             96%             89%           88%               65%              88%
    Exploration                                              1%              6%            2%                1%               5%
Average year-end crude oil price, per barrel        $    21.02      $    20.94    $     7.96        $    13.91       $    22.22
Average year-end natural gas price, per mcf         $    14.63      $     2.77    $     1.68        $     2.13       $     2.79
</TABLE>
----------------------
(1)  We have reduced the pre-tax present value of proved reserves and the future
     net revenues of certain properties to reflect applicable abandonment costs
     and, with respect to the LA Basin Properties, a net profits interest owned
     by a third party.
(2)  A 50% net profits interest attaches to the net proceeds from approximately
     7.4 million barrels of our proved reserves in the L.A. Basin at December
     31, 2000.
(3)  The reserve replacement ratio is calculated by dividing (a) the sum of
     reserves added during each respective year through purchases of reserves in
     place, extensions, discoveries and other additions and the effect of
     revisions, if any, by (b) each respective years' production.
(4)  The reserve replacement ratio and reserve replacement cost per BOE for 1998
     is negative due to a negative volume revision related to low crude oil
     prices at December 31, 1998.
(5)  Pro forma as if the acquisitions of the Montebello and Arroyo Grande Fields
     occurred on January 1, 1997. Such acquisitions closed in March and November
     1997, respectively, with effective dates of February 1, 1997, and November
     1, 1997, respectively.
(6)  Reserve replacement cost per BOE for a year is calculated by dividing
     upstream capital costs incurred for such year by the sum of reserves added
     during each respective year through purchases of reserves in place,
     extensions, discoveries and other additions and the effect of revisions, if
     any.

 ACQUISITION AND EXPLOITATION

  Acquisition and Exploitation Strategy

   We are continually engaged in the exploitation and development of our
existing property base and the evaluation and pursuit of additional
underdeveloped properties for acquisition. We focus on mature but underdeveloped
producing crude oil properties in areas where we believe substantial reserve
additions and cash flow increases can be made through relatively low-risk
drilling, improved production practices and recovery techniques and improved
operating margins. Generally, we seek to improve a property's operating margin
by reducing costs, investing capital to increase production rates and enhancing
the marketing arrangements of the crude oil production.

  Once we identify a prospective property for acquisition, we conduct a
technical review of existing production and operating practices to identify and
quantify underexploited value. If the initial studies indicate undeveloped
potential, the various producing and potentially productive formations in the
area are mapped in detail. Historical production data is evaluated to determine
if additional wells or other capital expenditures appear necessary to optimize
the recovery of reserves from the property. Geologic and engineering information
and operating practices utilized by operators on offsetting leases are analyzed
to identify potential additional exploitation and development opportunities. A
market study is also performed

                                       6
<PAGE>

analyzing product markets, available pipeline connections, access to trading
locations and existing contractual arrangements with the goal of maximizing
sales and profit margins from the area. See "--Product Markets and Major
Customers". A comprehensive plan of exploitation is then prepared and used as a
basis for our offer to purchase.

  We seek to acquire a majority interest in the properties we have identified
and to act as operator of those properties. We have in the past, and may in the
future, hedge a significant portion of the acquired production, thereby
partially mitigating product price volatility that could have an adverse impact
on exploitation opportunities. If we successfully purchase properties, we then
implement our exploitation plan by modifying production practices, realigning
existing waterflood patterns, drilling wells and performing workovers,
recompletions and other production and reserve enhancements. After the initial
acquisition, we may also seek to increase our interest in the properties through
acquisitions of offsetting acreage, farmout drilling arrangements and the
purchase of minority interests in the properties.

  By implementing our exploitation plan, we seek to increase cash flows and
enhance the value of our asset base. The results of these activities are
reflected in additions and revisions to proved reserves. During the five-year
period ending December 31, 2000, net additions and revisions to proved reserves
totaled 122 million BOE or approximately 310% of cumulative net production for
this period. These reserves were added at an aggregate average cost of $3.04 per
BOE. This activity excludes reserves added as a result of our acquisition
activities. Reserve additions related solely to our acquisition activities
totaled 58 million BOE and were added at an aggregate average cost of $1.11 per
BOE.

  The properties in our four core areas represent approximately 99% of total
proved reserves at December 31, 2000. These properties were previously owned and
operated by major integrated oil and natural gas companies and are comprised of
underdeveloped crude oil properties that we believe to have significant upside
potential that can be evaluated through development and exploitation activities.
During 2001, we estimate that we will spend approximately $120.0 million on the
development and exploitation of our upstream crude oil and natural gas
properties. Approximately $100.0 million or 85% of these capital expenditures
are earmarked for exploitation projects in California. The 2001 capital program
incorporates the results of various analyses and field studies performed over
the last few years and includes the drilling and completion of approximately 217
total wells, including 56 injection wells. In addition, we plan to construct a
gas processing plant and a water processing plant at the Arroyo Grande field in
California. Activities to be conducted include a variety of primary, secondary
and tertiary recovery projects that we believe will expand our proved developed
reserve base, offset normal production decline and potentially generate a year-
over-year production increase of approximately 10%.

  Set forth below is a discussion of our upstream properties.

  Current Exploitation Projects

  The following table sets forth certain information with respect to our crude
oil and gas properties (dollars in millions):

<TABLE>
<CAPTION>
                                                        California Properties
                                           -------------------------------------------------
                                                                          Arroyo              Sunniland   Illinois     Point
                                            LA Basin       Montebello    Grande (4) Mt. Poso    Trend       Basin     Arguello
                                           ------------   -------------  ---------- --------- ----------- ---------- -----------
<S>                                        <C>            <C>            <C>        <C>       <C>         <C>        <C>
Year(s) Acquired                                   1992        1997        1997        1998    1993/1994      1995      1999
Year(s) Discovered                            1924-1966        1917        1906        1926    1943-1978      1905      1981
Proved reserves at acquisition - MMBOE             17.7        23.3        19.9         7.7          5.0      17.3       6.4

Cumulative from acquisition date:
Direct acquisition, development and
  exploitation capital spent                   $    198.4  $   57.8   $    34.8      $  25.6     $  87.0    $   86.7  $   8.1
Production - MMBOE                                   30.1       2.3         1.8          0.8         9.7         6.2      2.3
Cumulative gross margin (1)                    $    248.9  $   16.9   $     9.4      $   8.0     $  58.8    $   62.3  $  13.1
Aggregate reserve addition cost                $     1.54  $   2.31   $    0.55      $  3.50     $  3.05    $   2.92  $  1.08

As of December 31, 2000:
Proved Reserves - MMBOE                              98.8(2)   22.7        61.9          6.5        18.8        23.5      5.2
Proved Developed Reserves - MMBOE                    71.7       9.1         5.1          4.3        17.9        19.6      4.5
Future Net Revenues (3)                        $  2,010.8  $  266.1   $   104.0      $  60.8     $  53.8    $  333.0  $  44.8
Pre-tax Present Value of Proved Reserves (3)   $    929.6  $  113.0   $    38.0      $  38.0     $  41.2    $  133.1  $  38.8
% Pre-tax Present Value of
  Proved Developed Reserves                            77%       53%         82%          77%         90%         85%      85%
2000 Unit Gross Margin                         $    12.86  $  10.03   $    7.65      $ 11.00     $  0.95    $  10.70  $  6.05

Estimated development and exploitation
  capital budgeted in 2001                     $     54.7  $   13.7   $    14.2      $   9.5     $   6.6    $   14.3  $   7.0
</TABLE>
                                                     Footnotes on following page

                                       7
<PAGE>

-----------------
(1)  Represents revenues less production expenses from date of acquisition.
(2)  We own a 100% working interest in the L.A. Basin properties. A 50% net
     profits interest attaches to the net proceeds from approximately 7.4
     million barrels of our proved reserves in the L.A. Basin at December 31,
     2000.
(3)  We have reduced the pre-tax present value of proved reserves and the future
     net revenues of certain properties to reflect applicable abandonment costs
     and with respect to the LA Basin Properties, a net 50% profits interest
     owned by a third party.
(4)  High gas prices at December 31, 2000, had the impact of decreasing the
     value of the Arroyo Grande field, where we purchase gas to fuel steam
     generators. Future net revenues and the Present Value of Proves Reserves
     for the Arroyo Grande field at December 31, 2000, pro forma, to reflect the
     same crude oil prices and natural gas prices and related differentials as
     were used to price the value of the reserves at December 31, 1999 were
     $750.1 and $303.1 million respectively.

  Onshore California Properties. In 1992, we acquired Stocker Resources, a sole
purpose company formed in 1990 to acquire substantially all of Chevron USA's
producing crude oil properties in the LA Basin. These interests included the
Inglewood, East Beverly Hills, San Vicente and South Salt Lake fields. Following
the initial acquisition, we expanded our holdings in this area by acquiring
additional interests within the existing fields, including all of Texaco
Exploration and Production, Inc.'s interest in the Vickers Lease which further
consolidated our holdings in the Inglewood field. We refer to all of our
properties in the LA Basin acquired prior to 1997 collectively as the LA Basin
Properties. The LA Basin Properties consist of crude oil reserves discovered at
various times between 1924 and 1966. We have performed various exploitation
activities, including drilling additional production and injection wells,
returning previously marginal wells to economic production, optimizing pre-
existing waterflood operations, initiating new waterfloods, improving artificial
lift, increasing the capacity and efficiency of facilities, upgrading facilities
to maintain regulatory compliance, reducing unit production expenses and
improving marketing margins. Additionally, we continuously update and perform
technical studies to identify new investment opportunities on these properties.
Through these acquisition and exploitation activities, our net average daily
production from this area has increased from approximately 6,700 BOE per day in
1992 to an average of 11,000 BOE per day during the fourth quarter of 2000.

  Planned exploitation activities for the LA Basin Properties include:

 .  optimize and increase the inventory of opportunities at the Inglewood Field,
   the largest field, by developing a 3-D reservoir model;

 .  drilling additional wells to better define field limits of the western
   portion of the East Beverly Hills structure;

 .  development of a 3-D reservoir model of the East Beverly Hills field to
   assist with the planning and implementation of a Hauser zone waterflood in
   the western area and to further realign Hauser zone injection in the eastern
   part of the field;

 .  drilling additional wells at the San Vicente field to further develop the Hay
   interval; and

 .  evaluation of initiating water injection in the Hay zone at the San Vicente
   field and the Ogden zone at the East Beverly Hills field.

  Exploitation activity on the South Salt Lake field included the commencement
of gas injection in late 1999. Production response to injection has been
favorable but due to high gas prices, we have suspended gas injection and are
selling our gas production to maximize near-term cash flows. We will continue to
evaluate the injection program to optimize cash flow by either continuing gas
sales or reinitiating injection to increase oil revenues.

  During 1997 and 1998 we expanded our operations in the LA Basin with the
acquisition of the Montebello field, and expanded into other California areas
with the acquisition of the Arroyo Grande and Mt. Poso fields. Combined, these
three fields added approximately 50.9 million BOE to our proved reserves at the
acquisition dates.

  In March 1997, we completed the acquisition of Chevron's interest in the
Montebello field for approximately $25.0 million, effective February 1, 1997.
The assets acquired consisted of a 100% working interest and a 99.2% net revenue
interest in 55 producing crude oil wells and related facilities and
approximately 450 acres of surface fee land. The Montebello field is located
approximately 15 miles from our existing LA Basin operations. Our net average
daily production from this field has increased from approximately 930 BOE per
day at the acquisition date to approximately 1,900 BOE per day during the fourth
quarter of 2000.  Since the date of acquisition, we have drilled a total of 31
producing wells and 16 injection wells. During 2000, we deferred substantially
all capital investment activities at Montebello to evaluate the current
reservoir information provided by these wells and prepare a comprehensive
waterflood development plan.  The opportunities identified by this study are
scheduled to be substantially implemented during the next two years by the
drilling of up to 25 producing and 43 injection wells. Aggregate water injection
is forecasted to rise during the next 2 to 3 years from around 40,000 barrels to
75,000 barrels per day as a result of this multi-year development program.

                                       8
<PAGE>

  In November 1997, we acquired a 100% working interest and a 97% net revenue
interest in the Arroyo Grande field which is located in San Luis Obispo County,
California from subsidiaries of Shell Oil Company ("Shell"). The Arroyo Grande
field was discovered in 1906 and has produced approximately 12 MMBOE (100% crude
oil) or approximately 5% of the estimated original crude oil in place. The
assets acquired included surface and development rights to approximately 1,000
acres included in the 1,500 acre unit. The field is under continuous steam
injection and at the acquisition date, was producing approximately 1,600 BOE per
day (approximately 1,500 BOE net to our interest) of 14 degree API gravity crude
oil from 70 wells. The aggregate consideration for the Arroyo Grande field
consisted of (1) rights to a non-producing property interest conveyed to Shell,
(2) the issuance of 46,600 shares of Series D Cumulative Convertible Preferred
Stock with an aggregate stated value of $23.3 million, and (3) a five-year
warrant to purchase 150,000 shares of our common stock at $25.00 per share. No
proved reserves had been assigned to the rights to the property interest
conveyed. Our net average daily production from this field was approximately
1,600 BOE per day during the fourth quarter of 2000. Since acquiring this
property we have drilled additional wells to downsize the thermal development
pattern from 5 acres to 1.25 acres, and realigned steam injection within the
previously developed area.

  Planned exploitation activities for the Arroyo Grande field include:

 .  a multi-year drilling program to expand the area under continuous steam
   injection by developing additional 1.25 acre patterns;

 .  construction of a gas processing plant that will allow us to utilize produced
   gas as a fuel source and mitigate purchases of third party gas; and

 .  evaluation of the feasibility to construct a reverse osmosis facility to
   process produced water to provide an alternative to reinjecting this water
   into the producing formation, and thereby enhance the efficiency of the
   thermal recovery process.

  During 1998, we acquired the Mt. Poso field from Aera Energy LLC for
approximately $7.7 million. The field is located approximately 27 miles north of
Bakersfield, California, in Kern County. At acquisition, the field was producing
900 BOE per day of 15 - 17 degree API gravity crude and added approximately 7.7
MMBOE to our proved reserves. Our net average daily production from this field
was approximately 1,900 BOE per day during the fourth quarter of 2000.  Since
acquisition, we have undertaken an aggressive recompletion and drilling program
targeting the Pyramid Hills formation.

  Planned exploitation activities for the Mt. Poso field include:

 .  full development of the updip area on 2.5 acre spacing;

 .  a pilot drilling project to determine the feasibility to further decrease the
   spacing to 1.25 acres; and

 .  expansion of the pilot air injection enhanced oil recovery ("EOR") project by
   increasing injection almost five fold.

  Sunniland Trend Properties. We have a 100% working interest in five producing
fields located in the Sunniland Trend in South Florida that were previously
owned and operated by Exxon Mobil Corporation. We acquired 50% of our interest
in the properties in 1993 and the remaining 50% in 1994. At the time of our
initial acquisition, production net to our interest was approximately 900 BOE
per day (100% crude). As a result of increasing our interest to 100%,
development drilling on the property, and the implementation of exploitation
activities designed primarily to repair failed wells and to increase the fluid
lift capacity of certain wells, our net production peaked at an annual average
of 5,300 BOE per day in 1997. During 2000, production from this area averaged
1,900 BOE per day. The production decrease is primarily due to the effects of
natural decline. In late 2000, production commenced from a horizontal well
drilled to evaluate a prospective structural extension at the Raccoon Point
Field. This area was identified by a 14.4 square-mile 3-D seismic survey we
acquired in late 1999. The test well has produced steadily at a net rate of 400
BOE per day since completion in December 2000. We believe there is a potential
for increased crude oil production if we are successful in de-watering the
reservoir. We may drill additional wells to further develop the structure.

  Illinois Basin Properties. In December 1995, we acquired all of Marathon Oil
Company's producing and nonproducing upstream crude oil and natural gas assets
in the Illinois Basin for approximately $51.5 million. Our initial exploitation
plan for the Illinois Basin Properties included improving the unit gross margin
by decreasing unit production expenses and increasing price realizations. Unit
production expenses for these properties, which averaged $12.00 per BOE in the
fourth quarter of 1995, averaged approximately $9.42 per BOE during 2000. Our
net average daily production from this property was approximately 2,800 BOE per
day (100% crude) during 2000.

                                       9
<PAGE>

  Planned exploitation for the Illinois Basin Properties include:

 .  drilling approximately 50 infill wells; and

 .  feasibility evaluation and potential implementation of a pilot program to
   field test an alkaline-surfactant-polymer ("ASP") EOR process.

  California Outer Continental Shelf ("OCS") Properties. In July 1999, Arguello
Inc., our wholly owned subsidiary, acquired Chevron's interests in the Point
Arguello Project for approximately $1.0 million. The acquisition, which was
funded from our working capital, had an effective date of July 1, 1999. The
interests acquired include Chevron's 26.3% working interest in the Point
Arguello Unit, its 26.3% interest in various partnerships owning the associated
transportation, processing and marketing infrastructure, and Chevron's 26.3%
right to participate in the adjacent Rocky Point Unit. We assumed Chevron's
26.3% share of (1) plugging and abandoning all existing well bores, (2) removing
conductors, (3) flushing hydrocarbons from all lines and vessels and (4)
removing/abandoning all structures, fixtures and conditions created subsequent
to closing. Chevron retained the obligation for all other abandonment costs,
including but not limited to (1) removing, dismantling and disposing of the
existing offshore platforms, (2) removing and disposing of all existing
pipelines and (3) removing, dismantling, disposing and remediation of all
existing onshore facilities. Arguello Inc. is the operator of record for the
Point Arguello Unit and has entered into an outsourcing agreement with a unit of
Torch Energy Advisors for the conduct of nonsupervisory field operations,
certain staff level professionals and substantially all administrative services.
In November 2000, Arguello was also named the operator of record for the Rocky
Point Unit. At acquisition, gross production from the field was approximately
20,100 BOE per day (approximately 5,200 BOE per day, net to our interest) from
25 wells located on 3 offshore platforms. The acquisition added approximately
6.4 MMBOE (100% crude) to our proved reserves. Our net average daily production
from this property was approximately 4,100 BOE per day during the fourth quarter
of 2000.

  Planned exploitation activities for Point Arguello include:

 .  completion of the initial interpretation of three merged and reprocessed 3-D
   seismic surveys across Point Arguello and the nearby Rocky Point structures
   and integrating the geophysical data with the subsurface control to develop a
   cohesive 3-D structural model;

 .  integration of historical down-hole fluid production profiles into the 3-D
   structural model to potentially identify prospective underdeveloped areas
   which may have been prematurely abandoned;

 .  initiation of a pilot program to drill horizontal wells to evaluate the Upper
   Monterey zone, an interval which has produced sporadically at Point Arguello
   with conventional wellbore drilling techniques;

 .  increasing fluid production rates from existing wells to potentially reduce
   natural decline and develop incremental reserves;

 .  seeking regulatory approval to allow near-term development of the adjacent
   Rocky Point Unit by drilling extended-reach wells from the Point Arguello
   platforms. While several critical regulatory permits and other agreements
   remain to be finalized, and a larger rig must be procured, we believe
   drilling of Rocky Point could occur around mid-year 2002; and

 .  reactivating cogeneration units at the onshore processing facility to sell up
   to 3.6 megawatts (net) of electricity.

  General. We believe that our properties in our four core areas hold potential
for additional increases in production, reserves and cash flow. However, our
ability to achieve such increases could be adversely affected by future
decreases in the demand for crude oil and natural gas, impediments in marketing
production, operating risks, unavailability of capital, adverse changes in
governmental regulations or other currently unforeseen developments.
Accordingly, we can give no assurance that such increases will be achieved.

  We believe that attractive acquisition opportunities that fit our criteria
will continue to be made available by both major and independent oil companies.
In addition to more typical acquisitions, we also intend to pursue joint
ventures and strategic alliances that provide us the opportunity to use our
exploitation and operating skills and our capital without acquiring the entire
property interest. While we are continually evaluating such opportunities, there
can be no assurance that any of these efforts will be successful. Our ability to
continue to acquire attractive properties may be adversely affected by:

 .  a reduction in the number of attractive properties offered for sale;

 .  increased competition for properties from other independent oil companies;

 .  unavailability of capital;

 .  incorrect estimates of reserves;

 .  exploitation potential or environmental liabilities or other factors.

                                       10
<PAGE>

Although we have historically acquired producing properties located only in the
continental United States, from time to time we evaluate, and may in the future
seek to acquire, properties located outside the continental United States.

 DISPOSITION OF PROPERTIES

  We periodically evaluate, and from time to time have elected to sell, certain
of our mature producing properties that we consider to be nonstrategic or fully
valued. Such sales enable us to focus on our core properties, maintain financial
flexibility, reduce overhead and redeploy the proceeds therefrom to activities
that we believe have a higher potential financial return. We have not made any
material sales of our producing properties during our last three fiscal years.

MIDSTREAM ACTIVITIES

 GENERAL

  We conduct our midstream activities through PAA, which was formed in 1998 to
acquire and operate the business and assets of our wholly owned midstream
subsidiaries. PAA engages in interstate and intrastate crude oil transportation,
terminalling and storage, as well as crude oil gathering and marketing
activities.

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

 .  increasing and optimizing the amount of crude oil we transport on our various
   pipeline and gathering assets;

 .  realizing cost efficiencies through operational improvements and potential
   strategic alliances;

 .  utilizing our Cushing Terminal and other assets to service the needs of
   refiners and to profit from merchant activities that take advantage of crude
   oil pricing and quality differentials; and

 .  pursuing strategic and accretive acquisitions of crude oil pipeline assets,
   gathering systems and terminalling and storage facilities that complement our
   existing asset base and distribution capabilities.

  Our midstream line of business consists of:

 .  gathering crude oil from the fields where the crude oil is produced;

 .  interstate and intrastate transportation of crude oil through pipelines,
   trucks or barges;

 .  storing crude oil in our storage tanks;

 .  transferring crude oil from pipelines and storage tanks to trucks, barges or
   other pipelines through our terminals;

 .  marketing crude oil produced by Plains Resources;

 .  the purchase of crude oil at the well and the bulk purchase of crude oil at
   pipeline and terminal facilities; and

 .  the subsequent resale or exchange of crude oil at various points along the
   crude oil distribution chain.

  The principal assets used in this segment include:

 .  a 3.1 million barrel, above-ground crude oil storage and terminal facility at
   Cushing, Oklahoma;

 .  the 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 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.

  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 "Midstream Acquisitions and Dispositions".

                                       11
<PAGE>

UNAUTHORIZED TRADING LOSSES

 Background

  In November 1999, we discovered that a former employee of PAA had engaged in
unauthorized trading activity, resulting in a loss of approximately $174.0
million, which includes 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 $8.0
million charge for litigation related to the unauthorized trading losses.

  Normally, as PAA purchases crude oil, it establishes 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
PAA's 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 PAA's 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, PAA 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 PAA's systems, policies and
procedures. As a result, PAA has developed a new written policy document and
manual of procedures designed to enhance its processes and procedures and
improve its 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 PAA sent a notice to each of its material
counter-parties that no person at PAA was authorized to enter into off-market
transactions. In addition, PAA has taken the following actions:

 .  PAA has communicated its trading strategies and risk tolerance to its traders
   by more clearly and specifically defining those strategies and risk limits in
   its written procedures.

 .  The new procedures require (i) more comprehensive and frequent reporting that
   will allow PAA 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 PAA's 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 its material counter-parties that
   off-market trading is against PAA's policy and that any written evidence to
   the contrary is unauthorized and false, the Risk Manager and other PAA
   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.

                                       12
<PAGE>

  We can give no assurance that the above steps will serve to detect and prevent
all violations of PAA's 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 PAA's then-existing credit facilities and significant
short-term cash and letter of credit requirements. In December 1999, PAA
executed amended credit facilities and obtained default waivers from all of its
lenders. PAA paid approximately $13.7 million to its lenders in connection with
the amended credit facilities. In connection with the amendments, we loaned
approximately $114.0 million to PAA. We financed the $114.0 million that we
loaned PAA with:

 .  the issuance of a new series of our Series F preferred stock for proceeds of
   $50.0 million;

 .  cash distributions of approximately $9.0 million made in November 1999 to
   PAA's general partner; and

 .  $55.0 million of borrowings under our revolving credit facility.

  On May 8, 2000, PAA entered into new bank credit agreements to refinance their
existing bank debt and repay the $114.0 million owed to us. The new bank credit
agreements also provide PAA with additional flexibility for working capital,
capital expenditures and other general corporate purposes. See Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources".

  Although one of our wholly owned subsidiaries is the general partner of and
owns 54% of PAA, the trading losses do not affect the operations or assets of
our upstream business. The debt of PAA is nonrecourse to us. In addition, our
indirect ownership in PAA does not collateralize any of our credit facilities.
Our $225.0 million credit facility is collateralized by our oil and natural gas
properties.

  In the period immediately following the disclosure of the unauthorized trading
losses, a significant number of PAA's suppliers and trading partners reduced or
eliminated the open credit previously extended to PAA. Consequently, the amount
of letters of credit PAA needed to support the level of its crude oil purchases
then in effect increased significantly. Some of PAA's 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 and $2.1 million,
respectively, excluding the positive impact of current favorable market
conditions.

  After the public announcement of the trading losses, class action lawsuits
were filed against us and PAA. 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 PAA reached an agreement to settle all
of the class actions and the Delaware derivative action. See Item 3. - "Legal
Proceedings".

 MIDSTREAM 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.

  Murphy Oil Company Ltd. Midstream Operations

  On March 1, 2001, PAA 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.

                                       13
<PAGE>

  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

  PAA has 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
PAA's 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 PAA's stated
policy of maintaining a strong capital structure by funding acquisitions with a
balance of debt and equity, PAA intends to refinance a portion of its 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 the general partner for total cash consideration of $25.0 million.

  Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum,
was engaged in crude oil transportation, gathering and marketing. The assets
acquired included approximately 2,300 miles of active pipelines, numerous
storage terminals and a fleet of trucks. The largest asset is an 800-mile
pipeline and gathering system located in the Spraberry Trend in West Texas that
extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties,
Texas. The assets we acquired also included approximately one million barrels of
crude oil linefill.

 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. Financing
for the amounts paid at closing was provided by a draw under a previous credit
facility of PAA. 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.

                                       14
<PAGE>

 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 the outstanding debt of
PAA. 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 fields offshore and onshore 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 of
Crude Oil"). 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.

  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 our 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, Texaco and Sun
Operating L.P., which together own approximately 25% 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

                                       15
<PAGE>

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 PAA's 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.

<TABLE>
<CAPTION>
                                                                     Year Ended December 31,
                                         -------------------------------------------------------------------------------
                                         2000    1999    1998    1997    1996    1995    1994    1993     1992    1991
                                         ------  ------  ------  ------  ------  ------  ------  ------  ------- -------
                                                                      (barrels in thousands)
<S>                                      <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>     <C>
Average daily volumes received from:
  Point Arguello (at Gaviota)               18      20      26      30      41      60      73      63       47      29
  Santa Ynez (at Las Flores)                56      59      68      85      95      92      34       -        -       -
                                         ------  ------  ------  ------  ------  ------  ------  ------  ------- -------
    Total                                   74      79      94     115     136     152     107      63       47      29
                                         ======  ======  ======  ======  ======  ======  ======  ======  ======= =======
</TABLE>


  A wholly owned subsidiary of ours is the operator of record for the Point
Arguello Unit. All of the volumes attributable to our interests are committed
for transportation on the All American Pipeline and are subject to our Marketing
Agreement with PAA. 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, we are 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.

<TABLE>
<CAPTION>
                                     2000 (1)  1999    1998   1997   1996    1995   1994   1993    1992   1991
                                     --------- ------ ------- ------ ------ ------- ------ ------ ------- ------
                                                              (barrels in thousands)
<S>                                  <C>       <C>    <C>     <C>     <C>   <C>     <C>    <C>    <C>     <C>
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

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

  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.

<TABLE>
<CAPTION>
                                                   Year Ended December 31,
                                        ----------------------------------------------
                                         2000      1999     1998      1997      1996
                                        --------  -------  --------  --------  -------
                                                   (barrels in thousands)
<S>                                     <C>       <C>      <C>       <C>       <C>
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
                                      ========  =======  ========  ========  =======
</TABLE>

                                       16
<PAGE>

 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 the 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. 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 acquisition,
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 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.

                                       17
<PAGE>

 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 in 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. During 2000, approximately 3,300 barrels per day of the
supply on this system are from fields operated by us.

 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 terminal 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.

                                       18
<PAGE>

  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 each tank 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 continuously monitor real time
operational data and each tank is cathodically protected. In addition, each tank
is 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.

                                       19
<PAGE>

  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 (in thousands):

<TABLE>
<CAPTION>
                                                                        Year Ended December 31,
                                                               -------------------------------------------
                                                                2000     1999     1998     1997     1996
                                                               -------- -------- -------- -------- -------
<S>                                                            <C>      <C>      <C>      <C>      <C>
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
                                                              ======== ======== ======== ======== =======
</TABLE>


  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
236,000 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 PAA's suppliers and trading partners
reduced or eliminated the open credit previously extended to PAA. Consequently,
the amount of letters of credit PAA needed to support the level its crude oil
purchases then in effect increased significantly. In addition, the cost to PAA
of letters of credit increased under their credit facility. Some of PAA's
purchase contracts were terminated. As a result of these changes, aggregate
volumes purchased have declined from an average of 499,000 barrels per day for
the fiscal quarter preceding the trading loss to an average of 275,000 barrels
per day in the fourth quarter of 2000. Approximately 70,000 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".

  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              236        239       88        71        59
Bulk purchases                28        138       98        49        32
                        --------   --------  -------   -------   -------
  Total volumes              264        377      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

                                       20
<PAGE>

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 PAA, under which they are the exclusive
marketer/purchaser for all of our equity crude oil production. The Marketing
Agreement provides that they will purchase for resale at market prices all of
our crude oil production for which they 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
us or the 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, which includes estimated associated costs and legal
expenses. In 2000, we recognized an additional $8.0 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.

  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

                                       21
<PAGE>

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 23 in the notes to our consolidated financial statements located
elsewhere in this report for information with respect to the operating
activities of our upstream and midstream segments.

PRODUCT MARKETS AND MAJOR CUSTOMERS

  Our revenues are highly dependent upon the prices of, and demand for, crude
oil and natural gas. Historically, the markets for crude oil and natural gas
have been volatile historically, and are likely to continue to be volatile in
the future. The prices we receive for our crude oil and natural gas production
and the levels of such production are subject to wide fluctuations and depend on
numerous factors beyond our control, including seasonality, the condition of the
United States economy (particularly the manufacturing sector), foreign imports,
political conditions in other crude oil-producing and natural gas-producing
countries, the actions of the Organization of Petroleum Exporting Countries and
domestic government regulation, legislation and policies. Decreases in the
prices of crude oil and natural gas have had, and could have in the future, an
adverse effect on the carrying value of our proved reserves and our revenues,
profitability and cash flow. See "Item 7. - "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Outlook". Almost
all of our reserve base (approximately 94% of year-end 2000 reserve volumes) is
comprised of crude oil properties that are sensitive to crude oil price
volatility.


  Certain of our operations in California that have interruptible electrical
contracts have been adversely impacted by electrical service interruptions. We
estimate that our oil and gas production for 2000 and the first quarter of 2001
was adversely affected by approximately 43,000 BOE and 45,000 BOE, respectively,
as a result of such interruptions. Although under recent regulatory rulings we
believe that our operations will only be affected if rolling blackouts occur and
we have made operational changes to mitigate the effects of electrical
interruptions, there can be no assurance that our operations will not be
adversely impacted in the future by the California power market. Although we are
not currently experiencing any significant involuntary curtailment of our crude
oil or natural gas production, market, logistic, economic and regulatory factors
may in the future materially affect our ability to sell our production.

                                       22
<PAGE>

  In order to manage our exposure to price risks in the marketing of our crude
oil and natural gas, from time to time we purchase put options, enter into fixed
price delivery contracts, floating price collar arrangements, financial swaps
and crude oil and natural gas futures contracts as hedging devices. To ensure a
fixed price for future production, we may sell a futures contract and thereafter
either (1) make physical delivery of our product to comply with such contract or
(2) buy a matching futures contract to unwind our futures position and sell our
production to a customer. These same techniques are also utilized to manage
price risk for certain production purchased from customers of PAA. Such
contracts may expose us to the risk of financial loss in certain circumstances,
including instances where production is less than expected, our customers fail
to purchase or deliver the contracted quantities of crude oil or natural gas, or
a sudden, unexpected event materially impacts crude oil or natural gas prices.
Such contracts may also restrict our ability to benefit from unexpected
increases in crude oil and natural gas prices. See Item 7. - "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Outlook" and Item 7a. - "Quantitative and Qualitative Disclosures about Market
Risks".

  Substantially all of our California crude oil and natural gas production and
our Sunniland Trend oil production is transported by pipelines, trucks and
barges owned by third parties. The inability or unwillingness of these parties
to provide transportation services to us for a reasonable fee could result in
our having to find transportation alternatives, increased transportation costs
or involuntary curtailment of a significant portion of our crude oil and natural
gas production.

  Certain of our natural gas production has been in the past, and may be in the
future, curtailed from time to time depending on the quality of the natural gas
produced and transportation alternatives. In addition, market, economic and
regulatory factors, including issues regarding the quality of certain of our
natural gas, may in the future adversely affect our ability to sell our natural
gas production.

  Deregulation of natural gas prices has increased competition and volatility of
natural gas prices. Prices received for our natural gas are subject to seasonal
variations and other fluctuations. All of our natural gas production is
currently sold under various arrangements at spot indexed prices. In certain
instances we enter into financial arrangements to hedge our exposure to spot
price fluctuations. See Item 2. - "Properties -- Production and Sales" and Item
7. - "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Outlook".

  Customers accounting for more than 10% of consolidated sales (excluding
hedging effects) for the periods indicated are as follows:

<TABLE>
<CAPTION>
                                                 Percentage of Consolidated Sales
                                          ------------------------------------------------
                                                      Year Ended December 31,
                                          ------------------------------------------------
Customer                                       2000             1999            1998
                                          ---------------  ---------------  --------------
<S>                                       <C>              <C>              <C>
Marathon Ashland Petroleum (1)                        12%              -               -
Sempra Energy Trading Corporation (1)                  -              22%             27%
Koch Oil Company (1)                                   -              18%             15%

                                           Percentage of Upstream Oil and Gas Sales (2)
                                          ------------------------------------------------

Chevron                                               43%             39%              -
Equiva Trading Company                                23%              -               -
Tosco Refining Company                                 -              19%             50%
Conoco Inc.                                            -              11%              -
Scurlock Permian LLC                                   -               -              17%
Marathon Ashland Petroleum                            13%             16%              -

</TABLE>
----------
(1)  These customers pertain to our midstream segment. Represents percentage of
     oil and gas sales revenues, plus marketing, transportation, storage and
     terminalling revenues.
(2)  PAA is the exclusive marketer/purchaser for all our equity crude oil
     production. These percentages represent the entities that purchased our
     equity crude production from PAA. We believe that the loss of an individual
     customer would not have a material adverse effect on our results of
     operations.

COMPETITION

 Crude Oil and Natural Gas Producing Activities

  Our competitors include major integrated oil and natural gas companies, and
numerous independent oil and natural gas companies, individuals and drilling and
income programs. Many of our larger competitors possess and employ financial and
personnel resources substantially greater than those available to us. Such
companies are able to pay more for productive crude oil and natural gas
properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number

                                       23
<PAGE>

of properties and prospects than our financial or human resources permit. Our
ability to acquire additional properties and to discover reserves in the future
will depend on our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment. In addition, there
is substantial competition for capital available for investment in the oil and
natural gas industry.

 Midstream Activities

  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.

 OSHA

  We are subject to the requirements of the federal Occupational Safety and
Health Act, as amended ("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.

 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 OSHA with respect to our trucking 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.

                                       24
<PAGE>

  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.

 Transportation of Crude Oil

  General Interstate Regulation. Our interstate common carrier pipeline
operations are subject to rate regulation by the FERC under the Interstate
Commerce Act. The Interstate Commerce Act requires that tariff rates for
petroleum pipelines, which includes crude oil, as well as refined product 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 may
require the pipeline operator to refund to shippers, with interest, any
difference between the rates the FERC determines to be lawful and the rates
under investigation. In addition, the FERC will order the pipeline to change its
rates prospectively to the lawful level.

  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. Under a cost-
of-service basis, rates are permitted to generate operating revenues, on the
basis of projected volumes, not greater than the total of the following:

  .  operating expenses;
  .  depreciation and amortization;
  .  federal and state income taxes; and
  .  an overall 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.

                                       25
<PAGE>

  Our Crude Oil 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 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.

 Transportation and Sale of Natural Gas

  Prior to January 1993, the FERC, under the Natural Gas Policy Act of 1978
("NGPA"), prescribed maximum lawful prices for natural gas sales.  Effective
January 1, 1993, natural gas prices were completely deregulated.  Consequently,
sales of our natural gas after such date have been made at market prices.

  The FERC regulates interstate natural gas pipeline transportation rates and
service conditions, both of which affect our marketing of gas, as well as our
revenues from sales of such gas. Since the latter part of 1985, culminating in
1992 in the Order No. 636 series of orders, the FERC has endeavored to make
natural gas transportation more accessible to gas buyers and sellers on an open
and non-discriminatory basis. FERC's "open access" policies are designed to
improve the competitive structure of the interstate natural gas pipeline
industry and to create a regulatory framework that will put gas sellers into
more direct contractual relations with gas buyers. As a result of the Order No.
636 program, the marketing and pricing of natural gas has been significantly
altered. The interstate pipelines' traditional role as wholesalers of natural
gas has been terminated and replaced by regulations which require pipelines to
provide transportation and storage service to others who buy and sell natural
gas. In addition, on February 9, 2000, FERC issued Order No. 637, promulgating
new regulations designed to refine the Order No. 636 "open access" policies and
revise the rules applicable to capacity release transactions. These new rules
will, among other things, permit existing holders of firm capacity to release or
"sell" their capacity to others at rates in excess of FERC's regulated rate for
transportation services.

  Although the FERC does not regulate natural gas producers such as ourselves,
the agency's actions are intended to foster increased competition within all
phases of the natural gas industry. To date, the FERC's pro-competition policies
have not materially affected our business or operations. It is unclear what
impact, if any, future rules or increased competition within the natural gas
transportation industry will have on our gas sales efforts.

  Additional proposals and/or proceedings that might affect the natural gas
industry may be considered by FERC, Congress, or state regulatory bodies. We
cannot predict when or if any of these proposals may become effective or what
effect, if any, they may have on our operations. The natural gas industry has
historically been very heavily regulated; thus there is no assurance that the
less stringent regulatory approach recently pursued by the FERC and Congress
will continue indefinitely into the future. The regulatory burden on the oil and
natural gas industry increases our cost of doing business and, consequently,
affects our profitability and cash flow. In as much as laws and regulations are
frequently expanded, amended or reinterpreted, we are unable to predict the
future cost or impact of complying with such regulations. We do not believe,
however, that our operations will be affected any differently than other gas
producers or marketers with which we compete.

 Regulation of Production

  The production of crude oil and natural gas is subject to regulation under a
wide range of federal and state statutes, rules, orders and regulations. State
and federal statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. The states in which we own and
operate properties have regulations governing conservation matters, including
provisions for the unitization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from crude oil and natural gas
wells and the regulation of the spacing, plugging and abandonment of wells. Many
states also restrict production to the market demand for oil and natural gas and
several states have indicated interest in revising applicable regulations. The
effect of these regulations is to limit the amount of oil and natural gas we can
produce from our wells and to limit the number of wells or the locations at
which we can drill. Moreover, each state generally imposes an ad valorem,
production or severance tax with respect to production and sale of crude oil,
natural gas and natural gas liquids within its jurisdiction.

                                       26
<PAGE>

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.

  Although we obtained environmental studies on our properties in California,
the Sunniland Trend and the Illinois Basin, and we believe that such properties
have been operated in accordance with standard oil field practices, certain of
the fields have been in operation for more than approximately 90 years, and
current or future local, state and federal environmental laws and regulations
may require substantial expenditures to comply with such rules and regulations.
In December 1995, we negotiated an agreement with Chevron, a prior owner of the
LA Basin Properties, to remediate sections of the properties impacted by prior
drilling and production operations. Under this agreement, Chevron agreed to
investigate and potentially remediate specific areas contaminated with hazardous
components, such as volatile organic substances and heavy metals, and we agreed
to excavate and remediate nonhazardous crude oil contaminated soils. We are
obligated to construct and operate (for the next 10 years) a minimum of five
acres of bioremediation cells for crude oil contaminated soils designated for
excavation and treatment by Chevron. Although we believe that we do not have any
material obligations for operations conducted prior to Stocker's acquisition of
the properties from Chevron, other than our obligation to plug existing wells
and those normally associated with customary oil field operations of similarly
situated properties (such as the Chevron agreement described above), there can
be no assurance that current or future local, state or federal rules and
regulations will not require us to spend material amounts to comply with such
rules and regulations or that any portion of such amounts will be recoverable
from Chevron, either under the December 1995 agreement or the limited indemnity
from Chevron contained in the original purchase agreement.

  A portion of our Sunniland Trend properties is located within the Big Cypress
National Preserve and our operations therein are subject to regulations
administered by the National Park Service ("NPS"). Under such regulations, a
Master Plan of Operations has been approved by the Regional Director of the NPS.
The Master Plan of Operations is a comprehensive plan of practices and
procedures for our drilling and production operations designed to minimize the
effect of such operations on the environment. The Master Plan of Operations must
be modified and permits must be secured from the NPS for new wells that require
the use of additional land for drilling operations. The Master Plan of
Operations also requires that we restore the surface property affected by
drilling and production operations upon cessation of these activities. We do not
anticipate that expenditures required to comply with such regulations will have
a material adverse effect on current operations.

  Approximately 183 acres of the 450 acres acquired in the Montebello Field have
been designated as California Coastal Sage Scrub, a known habitat for the
gnatcatcher, a species of bird designated as a federal threatened species under
the Endangered Species Act. Approximately 40 pairs of gnatcatchers are believed
to inhabit the property. In addition, the 450 acres acquired have been or will
shortly be committed to the Natural Community Conservation Program/Coastal Sage
Scrub Project, a voluntary conservation program. A variety of existing laws,
rules and guidelines govern activities that can be conducted on properties that
contain coastal sage scrub and gnatcatchers. These laws, rules and guidelines
generally limit the scope of operations that can be conducted on such properties
to those activities which do not materially interfere with such vegetation, the
gnatcatcher or its habitat. Although there can be no assurance that the presence
of coastal sage scrub and gnatcatchers on the Montebello Field and existing or
future laws, rules and guidelines will not prohibit or limit our operations and
our planned activities or future commercial and/or residential development, we
believe that we will be able to operate the existing wells and realize the
reserve potential identified in our acquisition analysis without undue
restrictions or prohibitions.

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<PAGE>

 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.

 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") required 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 included a new operating permit for major sources ("Title V
permits"), which applied to some of our facilities. Implementation of the 1990
Federal Clean Air Act Amendments has not had 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

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<PAGE>

"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.

 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.

FEDERAL TAXATION

  For federal income tax purposes, Plains All American Inc. is the general
partner of PAA, holding a direct and indirect ownership at December 31, 2000 of
approximately 54% in PAA. Because PAA is a pass-through entity for tax purposes,
the income or loss of PAA is generally allocated based upon the owners'
respective ownership percentage. However, the Internal Revenue Code requires
certain items of partnership income, deduction, gain or loss to be allocated so
as to account for the difference between the tax basis and the fair market value
of the property contributed to PAA by the general partner. The federal income
tax burden associated with the difference between allocations based upon the
fair market value of the property contributed by the general partner and the
actual tax basis established for such property will be borne by the general
partner.

  At December 31, 2000, we and our subsidiaries that are taxed as corporations
for federal income tax purposes, which together file a consolidated federal
income tax return, had remaining federal income tax net operating loss ("NOL")
carryforwards of approximately $183.9 million and approximately $165.0 million
of alternative minimum tax ("AMT") net operating loss carryforwards available as
a deduction against future AMT income. In addition, we had approximately $2.4
million of enhanced oil recovery credits, $2.3 million of AMT credits and $7.0
million of statutory depletion carryforwards at December 31, 2000. The NOL
carryforwards expire from 2008 through 2019. The value of these carryforwards
depends on our ability to generate federal taxable income. In addition, for AMT
purposes, only 90% of AMT income in any given year may be offset by AMT NOLs.

  Our ability to utilize NOL carryforwards to reduce our future federal taxable
income and federal income tax is subject to various limitations under the
Internal Revenue Code of 1986, as amended (the "Code"). The utilization of such
carryforwards may be limited upon the occurrence of certain ownership changes,
including the issuance or exercise of rights to acquire stock, the purchase or
sale of stock by 5% stockholders, as defined in the Treasury Regulations, and
our offering of stock during any three-year period resulting in an aggregate
change of more than 50% ("Ownership Change") in our beneficial ownership.

  In the event of an Ownership Change, Section 382 of the Code imposes an annual
limitation on the amount of a corporation's taxable income that can be offset by
these carryforwards. The limitation is generally equal to the product of (1) the
fair market value of our equity multiplied by (2) a percentage approximately
equivalent to the yield on long-term tax-exempt bonds during the month in which
an Ownership Change occurs. In addition, the limitation is increased if there
are recognized built-in gains during any post-change year, but only to the
extent of any net unrealized built-in gains (as defined in the Code) inherent in
the assets sold. Although no assurances can be made, we do not believe that an
Ownership Change has occurred as of December 31, 2000. Equity transactions after
the date hereof by us or by 5% stockholders (including relatively small
transactions and transactions beyond our control) could cause an Ownership
Change and therefore a limitation on the annual utilization of NOLs.

                                       29
<PAGE>

  In the event of an Ownership Change, the amount of our NOLs available for use
each year will depend upon future events that cannot currently be predicted and
upon interpretation of complex rules under Treasury Regulations. If less than
the full amount of the annual limitation is utilized in any given year, the
unused portion may be carried forward and may be used in addition to successive
years' annual limitation.

OTHER BUSINESS MATTERS

  We must continually acquire, explore for, develop or exploit new crude oil and
natural gas reserves to replace those produced or sold. Without successful
drilling, acquisition or exploitation operations, our crude oil and natural gas
reserves and revenues will decline. Drilling activities are subject to numerous
risks, including the risk that no commercially viable crude oil or natural gas
production will be obtained. The decision to purchase, explore, exploit or
develop an interest or property will depend in part on the evaluation of data
obtained through geophysical and geological analyses and engineering studies,
the results of which are often inconclusive or subject to varying
interpretations. See "Item 2. - "Properties -- Crude Oil and Natural Gas
Reserves". The cost of drilling, completing and operating wells is often
uncertain. Drilling may be curtailed, delayed or canceled as a result of many
factors, including title problems, weather conditions, compliance with
government permitting requirements, shortages of or delays in obtaining
equipment, reductions in product prices or limitations in the market for
products. The availability of a ready market for our crude oil and natural gas
production also depends on a number of factors, including the demand for and
supply of crude oil and natural gas and the proximity of reserves to pipelines
or trucking and terminal facilities. See Item 1. - "Business - Product Markets
and Major Customers". Natural gas wells may be shut in for lack of a market or
due to inadequacy or unavailability of natural gas pipeline or gathering system
capacity.

  Substantially all of our California crude oil and natural gas production and
our Sunniland Trend oil production is transported by pipelines, trucks and
barges owned by third parties. The inability or unwillingness of these parties
to provide transportation services to us for a reasonable fee could cause us to
seek transportation alternatives, which in turn could result in increased
transportation costs to us or involuntary curtailment of a significant portion
of our crude oil and natural gas production.

  Our operations are subject to all of the risks normally incident to the
exploration for and the production of crude oil and natural gas, including
blowouts, cratering, oil spills and fires, each of which could result in damage
to or destruction of crude oil and natural gas wells, production facilities or
other property, or injury to persons. The relatively deep drilling conducted by
us from time to time involves increased drilling risks of high pressures and
mechanical difficulties, including stuck pipe, collapsed casing and separated
cable. Our operations in California, including transportation of crude oil by
pipelines within the city of Los Angeles, are especially susceptible to damage
from earthquakes and involve increased risks of personal injury, property damage
and marketing interruptions because of the population density of the area.
Although we maintain insurance coverage considered to be customary in the
industry, we are not fully insured against certain of these risks, including, in
certain instances, earthquake risk in California, either because such insurance
is not available or because of high premium costs.

  A pipeline may experience damage as a result of an accident or other 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 replacement cost or 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.

                                       30
<PAGE>

TITLE TO PROPERTIES

  Our properties are subject to customary royalty interests, liens incident to
operating agreements, liens for current taxes and other burdens, including other
mineral encumbrances and restrictions. We do not believe that any of these
burdens materially interferes with the use of such properties in the operation
of our business.

  We believe that we have generally satisfactory title to or rights in all of
our producing properties. As is customary in the oil and natural gas industry,
minimal investigation of title is made at the time of acquisition of undeveloped
properties. Title investigation is made and title opinions of local counsel are
generally obtained only before commencement of drilling operations. We believe
that we have satisfactory title to all of our other 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 PAA's predecessor or us, we believe 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.

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

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

EMPLOYEES

  As of December 31, 2000, we had approximately 1,100 full-time employees, none
of whom is represented by any labor union. Approximately 675 of such full-time
employees are field personnel involved in crude oil and natural gas producing
activities, trucking and transport activities and crude oil terminalling and
storage activities. Approximately 915 employees spend the majority of their time
on the business of PAA.

ITEM 2.  PROPERTIES

  We are an independent energy company that is engaged in two related lines of
business. Our first line of business, which we refer to as "upstream", acquires,
exploits, develops, explores and produces crude oil and natural gas. Our second
line of business, which we refer to as "midstream", is engaged in the 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". We conduct
this second line of business through our majority ownership in PAA. Our upstream
crude oil and natural gas activities are focused in California in the Los
Angeles Basin, the Arroyo Grande Field, and the Mt. Poso Field, California OCS
in the Point Arguello Field, the Sunniland Trend of South Florida and the
Illinois Basin in southern Illinois. Our midstream activities are concentrated
in California, Texas, Oklahoma, Louisiana, Illinois and the Gulf of Mexico.

                                       31
<PAGE>

OIL AND NATURAL GAS RESERVES

  The following tables set forth certain information with respect to our
reserves based upon reserve reports prepared by the independent petroleum
consulting firms of H.J. Gruy and Associates, Inc., Netherland, Sewell &
Associates, Inc., and Ryder Scott Company. Such reserve volumes and values were
determined under the method prescribed by the SEC, which requires the
application of year-end prices for each year, held constant throughout the
projected reserve life.

<TABLE>
<CAPTION>

                                                             As of or for the Year Ended December 31,
                                         -----------------------------------------------------------------------------
                                                  2000                          1999                     1998
                                         -----------------------       ---------------------      --------------------
                                           Oil           Gas             Oil           Gas          Oil          Gas
                                          (Bbl)         (Mcf)           (Bbl)         (Mcf)        (Bbl)        (Mcf)
                                         --------      ---------       --------      -------      -------     --------
                                                                          (in thousands)
<S>                                      <C>           <C>             <C>           <C>          <C>         <C>
PROVED RESERVES
  Beginning balance                        218,922        90,873        120,208        86,781      151,627       60,350
  Revision of previous estimates            (9,834)       (3,597)        62,895        (8,234)     (46,282)       2,925
  Extensions, discoveries, improved
    recovery and other additions            22,429         9,252         37,393        15,488       14,729       29,306
  Sales of reserves in-place                     -             -              -             -            -       (2,799)
  Purchase of reserves in-place                  -             -          6,442             -        7,709            -
  Production                                (8,355)       (3,042)        (8,016)       (3,162)      (7,575)      (3,001)
                                           -------        ------        -------        ------      -------       ------
  Ending balance                           223,162        93,486        218,922        90,873      120,208       86,781
                                           =======        ======        =======        ======      =======       ======
PROVED DEVELOPED RESERVES
  Beginning balance                        120,141        49,255         73,264        58,445       99,193       38,233
                                           =======        ======        =======        ======      =======       ======
  Ending balance                           123,532        52,184        120,141        49,255       73,264       58,445
                                           =======        ======        =======        ======      =======       ======
</TABLE>

  The following table sets forth the pre-tax Present Value of Proved Reserves at
December 31, 2000, 1999 and 1998.

<TABLE>
<CAPTION>
                                        2000           1999         1998
                                    ------------  ------------  ----------
                                                 (in thousands)
<S>                                 <C>           <C>           <C>
Proved developed                     $1,020,023    $  721,151     $185,961
Proved undeveloped                      325,369       524,898       40,982
                                     ----------    ----------     --------
    Total Proved                     $1,345,392    $1,246,049     $226,943
                                     ==========    ==========     ========
</TABLE>

  There are numerous uncertainties inherent in estimating quantities and values
of proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond our control. Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Because all reserve estimates are to some degree speculative, the quantities of
crude oil and natural gas that are ultimately recovered, production and
operating costs, the amount and timing of future development expenditures and
future crude oil and natural gas sales prices may all differ from those assumed
in these estimates. In addition, different reserve engineers may make different
estimates of reserve quantities and cash flows based upon the same available
data. Therefore, the Present Value of Proved Reserves shown above represents
estimates only and should not be construed as the current market value of the
estimated crude oil and natural gas reserves attributable to our properties. The
information set forth in the preceding tables includes revisions of reserve
estimates attributable to proved properties included in the preceding year's
estimates. Such revisions reflect additional information from subsequent
exploitation and development activities, production history of the properties
involved and any adjustments in the projected economic life of such properties
resulting from changes in product prices. A large portion of our reserve base
(approximately 94% of year-end 2000 reserve volumes) is comprised of crude oil
properties that are sensitive to crude oil price volatility. See Item 7. -
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Outlook".

  In accordance with the SEC guidelines, the reserve engineers' estimates of
future net revenues from our properties and the present value thereof are made
using crude oil and natural gas sales prices in effect as of the dates of such
estimates and are held constant throughout the life of the properties, except
where such guidelines permit alternate treatment, including the use of fixed and
determinable contractual price escalations. The crude oil price in effect at
December 31, 2000 is based on the year-end crude oil price with variations
therefrom based on location and quality of crude oil. The overall average prices
used in the reserve reports as of December 31, 2000 were $21.02 per barrel of
crude oil, condensate and natural gas liquids and $14.63 per Mcf of natural gas.
See Item 1. - "Business -- Product Markets and Major Customers". Historically,
the prices for

                                       32
<PAGE>

crude oil and natural gas have been volatile and are likely to continue to be
volatile in the future. See Item 7. - "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Outlook".

  Since December 31, 1999, we have not filed any estimates of total proved net
crude oil or natural gas reserves with any federal authority or agency other
than the SEC. See Note 20 in our consolidated financial statements appearing
elsewhere in this report for certain additional information concerning our
proved reserves.

PRODUCTIVE WELLS AND ACREAGE

  As of December 31, 2000, we had working interests in 1,875 gross (1,855 net)
active producing oil wells. The following table sets forth certain information
with respect to our developed and undeveloped acreage as of December 31, 2000.


<TABLE>
<CAPTION>
                                           December 31, 2000
                            ------------------------------------------------
                             Developed Acres (1)       Undeveloped Acres (2)
                            ----------------------    ----------------------
                              Gross         Net         Gross        Net (3)
                            ---------    ---------     --------     --------
<S>                          <C>          <C>          <C>          <C>
Onshore California (4)          8,889        8,844        3,879       2,323
Offshore California (5)        15,326        4,033       41,720       1,449
Florida                        12,025       12,025       76,483      73,863
Illinois                       16,413       14,424       14,095       5,777
Indiana                         1,155          854        1,280         575
Kansas                              -            -       48,147      37,647
Kentucky                            -            -        1,321         521
Louisiana                           -            -        4,875       4,858
                               ------       ------      -------     -------
  Total                        53,808       40,180      191,800     127,013
                               ======       ======      =======     =======
</TABLE>

------------
(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acres are acres on which wells have not been drilled or
    completed to a point that would permit the production of commercial
    quantities of oil and natural gas, regardless of whether such
    acreage contains proved reserves.
(3) Less than 10% of total net undeveloped acres are covered by leases
    that expire from 2001 through 2003.
(4) Does not include 9,000 acres covered by a farmout from Chevron, in
    which we own a 46.25% interest.
(5) Does not include 6,200 acres under an option agreement, in which we
    have the right to acquire a 26.315% interest.

DRILLING ACTIVITIES

  Certain information with regard to our drilling activities during the years
ended December 31, 2000, 1999 and 1998 is set forth below:

<TABLE>
<CAPTION>

                                                   Year Ended December 31,
                        --------------------------------------------------------------------------
                                  2000                     1999                      1998
                        -----------------------   -----------------------  -----------------------
                           Gross         Net         Gross        Net         Gross         Net
                        -----------  ----------   ----------  -----------  -----------  ----------
<S>                      <C>         <C>          <C>          <C>         <C>          <C>
Exploratory Wells:
  Oil                         --           --          --          --            --          --
  Natural gas                 --           --          --          --            --          --
  Dry                         --           --        1.00        0.50            --          --
                          ------       ------      ------      ------         -----       -----
    Total                     --           --        1.00        0.50            --          --
                          ======       ======      ======      ======         =====       =====
Development Wells:
  Oil                     158.00       156.00      105.00      105.00         76.00       76.00
  Natural gas                 --           --          --          --            --          --
  Dry                       2.00         2.00          --          --            --          --
                          ------       ------      ------      ------         -----       -----
    Total                 160.00       158.00      105.00      105.00         76.00       76.00
                          ======       ======      ======      ======         =====       =====
Total Wells:
  Oil                     158.00       156.00      105.00      105.00         76.00       76.00
  Natural gas                 --           --          --          --            --          --
  Dry                       2.00         2.00        1.00        0.50            --          --
                          ------       ------      ------      ------         -----       -----
    Total                 160.00       158.00      106.00      105.50         76.00       76.00
                          ======       ======      ======      ======         =====       =====
</TABLE>

                                       33
<PAGE>

  See Item 1. - "Business -- Acquisition and Exploitation" and -- "Productive
Wells and Acreage" for additional information regarding exploitation activities,
including waterflood patterns, workovers and recompletions.

PRODUCTION AND SALES

  The following table presents certain information with respect to crude oil and
natural gas production attributable to our properties, the revenue derived from
the sale of such production, average sales prices received and average
production costs during the three years ended December 31, 2000, 1999 and 1998.

<TABLE>
<CAPTION>
                                                         Year Ended December 31,
                                                ---------------------------------------
                                                    2000          1999          1998
                                                ------------  ------------  -----------
                                                 (in thousands except per unit data)
<S>                                             <C>           <C>           <C>
Production:
  Crude oil and natural gas liquids (Bbls)          8,355          8,016         7,575
  Natural gas (Mcf)                                 3,042          3,162         3,001
  BOE                                               8,862          8,543         8,075

Revenue:
  Crude oil and natural gas liquids
  Sales                                          $133,325       $111,128      $ 98,664
  Natural gas                                      16,017          5,095         4,090
                                                 --------       --------      --------
    Total                                        $149,342       $116,223      $102,754
                                                 ========       ========      ========

Average sales price:
  Crude oil and natural gas liquids per Bbl      $  15.96       $  13.85      $  13.03
  Natural gas per Mcf                                5.26           1.61          1.36
  Per BOE                                           16.85          13.61         12.73
Production expenses per BOE                          7.01           6.51          6.29
</TABLE>

PAA PROPERTIES

  See description of PAA's properties under Item 1. - "Business - Midstream
Activities".

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, et al.  The suit alleged
that Plains All American Pipeline, L.P. and certain of the 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 the
general partner and us 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 our common stock and options, and is captioned
Koplovitz v. Plains Resources Inc., et al. The second consolidated action is
that filed by purchasers of PAA's 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 PAA reached an agreement with representatives for the plaintiffs for
the settlement of all of the class actions, and in January 2001, PAA deposited
approximately $30.0 million under the terms of the settlement agreement. The
total cost of the settlement to us and PAA, including interest and expenses and
after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million
was allocated to us by agreement between special independent committees of our
board of directors and the board of directors of Plains All American Inc. 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 the general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to PAA and its unitholders by failing to monitor properly the
activities of its employees. The court has consolidated all of the cases under

                                       34
<PAGE>

the caption In Re Plains All American Inc. Shareholders Litigation, and has
designated the complaint filed in Sussex v. Plains All American Inc. as the
operative 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 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 for the Southern District of Texas entitled
Fernandez v. Plains All American Inc., et al., naming the 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 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 legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition, results of operations or
cash flows.

ITEM 4.  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.

EXECUTIVE OFFICERS OF THE COMPANY

  Information regarding our executive officers is presented below. All executive
officers hold office until their successors are elected and qualified.

  Greg L. Armstrong, President and Chief Executive Officer    Officer Since 1981

  Mr. Armstrong, age 42, has been President, Chief Executive Officer and a
director since 1992. He was President and Chief Operating Officer from October
to December 1992, and Executive Vice President and Chief Financial Officer from
June to October 1992. He was Senior Vice President and Chief Financial Officer
from 1991 to June 1992, Vice President and Chief Financial Officer from 1984 to
1991, Corporate Secretary from 1981 to 1988, and Treasurer from 1984 to 1987.

  William C. Egg, Jr., Executive Vice President               Officer Since 1984

  Mr. Egg, age 49, has been Executive Vice President and Chief Operating
Officer-Upstream since May 1998. He was Senior Vice President from 1991 to 1998.
He was Vice President-Corporate Development from 1984 to 1991 and Special
Assistant-Corporate Planning from 1982 to 1984.

  Cynthia A. Feeback, Vice President - Accounting and Assistant Treasurer
                                                              Officer Since 1993

  Ms. Feeback, age 43, has been Vice President - Accounting and Assistant
Treasurer since May 1999. She was Assistant Treasurer, Controller and Principal
Accounting Officer of the Company from May 1998 to May 1999. She was Controller
and Principal Accounting Officer from 1993 to 1998. She was Controller from 1990
to 1993 and Accounting Manager from 1988 to 1990.

                                       35
<PAGE>

  Jim G. Hester, Vice President - Business Development and Acquisitions
                                                              Officer Since 1999

  Mr. Hester, age 41, has been Vice President - Business Development and
Acquisitions since May 1999. He was Manager of Business Development and
Acquisitions from 1997 to May 1999, Manager of Corporate Development from 1995
to 1997 and Manager of Special Projects from 1993 to 1995.  He was Assistant
Controller from 1991 to 1993, Accounting Manager from 1990 to 1991 and Revenue
Accounting Supervisor from 1988 to 1990.

  Phillip D. Kramer, Executive Vice President, Chief Financial Officer and
Treasurer                                                     Officer Since 1987

  Mr. Kramer, age 45, has been Executive Vice President and Chief Financial
Officer since May 1998. He was Senior Vice President and Chief Financial Officer
from May 1997 to May 1998. He was 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.

  Tim Moore, Vice President and General Counsel               Officer Since 2000

  Mr. Moore, age 43, has been Vice President, General Counsel and Secretary
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.

  Harry N. Pefanis, Executive Vice President                  Officer Since 1988

  Mr. Pefanis, age 43, has been Executive Vice President-Midstream since May
1998. He was Senior Vice President from February 1996 to May 1998. He had been
Vice President-Products Marketing since 1988. From 1987 to 1988 he was Manager
of Products Marketing. From 1983 to 1987 he was Special Assistant for Corporate
Planning. Mr. Pefanis is also President and Chief Operating Officer of Plains
All American Inc.

  Mary O. Peters, Vice President - Administration and Human Resources
                                                              Officer Since 1991

  Ms. Peters, age 52, has been Vice President-Administration and Human Resources
since 1991. She was Manager of Office Administration from 1984 to 1991.

  Al Swanson, Treasurer                                       Officer Since 2001

  Mr. Swanson, age 37, has been Treasurer since February 2001. He was Director
of Treasury of the Company from November 2000 to February 2001. Prior to joining
Plains Resources, he served as Treasurer of Santa Fe Snyder Corporation from
1999 and in various capacities at Snyder Oil Corporation including Director
Corporate Finance from 1998, Controller - SOCO Offshore, Inc., a wholly owned
subsidiary, from 1997, and Accounting Manager from 1992. Mr. Swanson began his
career with Apache Corporation in 1986 serving in internal audit and accounting.

                                       36
<PAGE>

                                    PART II

Item 5.  MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

  Our common stock is listed and traded on the American Stock Exchange under the
symbol "PLX". The number of stockholders of record of the common stock as of
March 22, 2001 was 1,088.

  The following table sets forth the range of high and low closing sales prices
for the common stock as reported on the American Stock Exchange Composite Tape
for the periods indicated below.

<TABLE>
<CAPTION>
                               High              Low
                           --------------   -------------
<S>                        <C>               <C>
2000:
1st Quarter                  $ 14 3/4          $ 10 1/2
2nd Quarter                    17                11
3rd Quarter                    20 1/8            13 13/16
4th Quarter                    21 3/4            16 7/8

1999:
1st Quarter                  $ 15 1/2             8 1/8
2nd Quarter                    20 3/16           13 1/8
3rd Quarter                    20                16 1/4
4th Quarter                    20                 9 1/16
</TABLE>

  We have not paid cash dividends on shares of our common stock since our
inception and do not anticipate paying any cash dividends on our common stock in
the foreseeable future. In addition, we are restricted by provisions of the
indentures governing the issue of $275.0 million 10.25% Senior Subordinated
Notes Due 2006 (the "10.25% Notes") and prohibited by our $225.0 million
revolving credit facility from paying dividends on our common stock.

                                       37
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA
         (IN THOUSANDS, EXCEPT FOR PER SHARE DATA)

  The following selected historical financial information was derived from, and
is qualified by reference to our consolidated financial statements, including
the notes thereto, appearing elsewhere in this report. The selected financial
data should be read in conjunction with the consolidated financial statements,
including the notes thereto, and "Item 7. - Management's Discussion and Analysis
of Financial Condition and Results of Operations" (in thousands, except per
share information).

<TABLE>
<CAPTION>

                                                                             Year Ended December 31,
                                                   ----------------------------------------------------------------------
                                                       2000           1999           1998           1997         1996
                                                   -------------  -------------   ------------   -----------  -----------
<S>                                                <C>            <C>             <C>            <C>          <C>
Statement of Operations Data:
Revenues:
  Oil and natural gas sales                          $  149,342    $   116,223     $  102,754    $  109,403   $   97,601
  Marketing, transportation,
    storage and terminalling revenues (1)             6,425,644     10,796,998      3,454,635     2,732,043    1,914,532
  Gain on PAA unit offerings (2)                              -          9,787         60,815             -            -
  Gain on sale of assets (3)                             48,188         16,457              -             -            -
  Interest and other income (4)                           7,411          1,237            834           319          309
                                                     ----------    -----------     ----------    ----------   ----------
    Total revenue                                     6,630,585     10,940,702      3,619,038     2,841,765    2,012,442
                                                     ----------    -----------     ----------    ----------   ----------
Expenses:
  Production expenses                                    62,140         55,645         50,827        45,486       38,735
  Marketing, transportation,
    storage and terminalling expenses (1)             6,292,615     10,689,308      3,416,274     2,719,563    1,905,001
  Unauthorized trading losses and
    related expenses (5)                                  7,963        166,440          7,100             -            -
  General and administrative (6)                         50,776         31,402         10,778         8,340        7,729
  Depreciation, depletion and amortization               47,221         36,998         31,020        23,778       21,937
  Reduction of carrying cost of oil
    and natural gas properties (7)                            -              -        173,874             -            -
  Interest expense                                       55,828         46,378         35,730        22,012       17,286
  Litigation settlement (8)                                   -              -              -             -        4,000
                                                     ----------    -----------     ----------    ----------   ----------
    Total expenses                                    6,516,543     11,026,171      3,725,603     2,819,179    1,994,688
                                                     ----------    -----------     ----------    ----------   ----------
Income (loss) before income taxes, minority
  interest, extraordinary item, and
  cumulative effect of accounting change                114,042        (85,469)      (106,565)       22,586       17,754
Minority interest                                        42,535        (40,203)           786             -            -
Income tax expense (benefit):
  Current                                                 1,020             (7)           862           352            -
  Deferred                                               24,563        (20,472)       (45,867)        7,975       (3,898)
                                                     ----------    -----------     ----------    ----------   ----------
Income (loss) before extraordinary item
  and cumulative effect of accounting change             45,924        (24,787)       (62,346)       14,259       21,652
Extraordinary item, net of tax benefit
  and minority interest (9)                              (4,988)          (544)             -             -       (5,104)
Cumulative effect of accounting change,
  net of tax benefit (10)                                  (121)             -              -             -            -
                                                     ----------    -----------     ----------    ----------   ----------
Net income (loss)                                        40,815        (25,331)       (62,346)       14,259       16,548
Less:  cumulative preferred stock dividends              14,725         10,026          4,762           163            -
                                                     ----------    -----------     ----------    ----------   ----------
Net income (loss) applicable to common shareholders  $   26,090    $   (35,357)    $  (67,108)   $   14,096   $   16,548
                                                     ==========    ===========     ==========    ==========   ==========
Income (loss) per common share - basic:
  Before extraordinary item                          $     1.75    $     (2.02)    $    (3.99)   $     0.85   $     1.32
  Extraordinary item                                      (0.28)         (0.03)             -             -        (0.31)
  Cumulative effect of accounting change                  (0.01)             -              -             -            -
                                                     ----------    -----------     -----------   ----------   ----------
                                                     $     1.46    $     (2.05)    $    (3.99)   $     0.85   $     1.01
                                                     ==========    ===========     ===========   ==========   ==========
Income (loss) per common share - diluted:
  Before extraordinary item                          $     1.56    $     (2.02)    $    (3.99)   $     0.77   $     1.23
  Extraordinary item                                      (0.17)         (0.03)             -             -        (0.29)
  Cumulative effect of accounting change                      -              -              -             -            -
                                                     ----------    -----------     -----------   ----------   ----------
                                                     $     1.39    $     (2.05)    $    (3.99)   $     0.77   $     0.94
                                                     ==========    ===========     ===========   ==========   ==========
</TABLE>

                                 Table and footnotes continued on following page

                                       38
<PAGE>

<TABLE>
<CAPTION>
                                                                           Year Ended December 31,
                                                  ---------------------------------------------------------------------
                                                      2000           1999           1998           1997         1996

                                                  ------------   ------------   ------------   -----------  -----------
<S>                                                <C>           <C>            <C>            <C>          <C>
Other Data:
Cash flow from operations (11)                      $ 100,640       $ 70,382       $ 42,033      $ 46,233     $ 39,942
Adjusted EBITDA (12)                                  179,228        139,116         80,344        68,376       56,977
Net cash provided by (used in) operating activities    35,860        (75,964)        37,630        30,307       39,008
Net cash used in investing activities                 130,183        266,396        483,422       107,634       52,496
Net cash provided by (used in) financing activities  (229,191)       404,044        448,622        78,524        9,876

                                                                              As of December 31,
                                                  ---------------------------------------------------------------------
                                                     2000           1999           1998           1997         1996

                                                  ------------   ------------   ------------   -----------  -----------
Balance Sheet Data:
Cash and cash equivalents                             $ 5,080       $ 68,228        $ 6,544       $ 3,714      $ 2,517
Working capital (deficit) (13)                         20,289        115,867        (21,041)       (6,011)      (4,843)
Property and equipment, net                           844,274        787,653        661,726       413,308      311,040
Total assets                                        1,394,329      1,689,560        972,838       556,819      430,249
Long-term debt                                        626,376        676,703        431,983       285,728      225,399
Other long-term liabilities                             3,422         21,107         10,253         5,107        2,577
Redeemable preferred stock                             50,000        138,813         88,487             -            -
Non-redeemable preferred stock,
  common stock and other stockholders' equity         137,140         40,619         69,170       133,193       95,572
</TABLE>
---------------
(1)  We have reclassified marketing, transportation, storage and terminalling
     revenues and expenses 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 marketing, transportation,
     storage and terminalling revenues and expenses for the years ended December
     31, 2000, 1999, 1998, 1997 and 1996 were $2.5 billion, $6.2 billion, $2.3
     billion, $2.0 billion and $1.4 billion, respectively. This reclassification
     had no effect on earnings.
(2)  For 1999, includes a $9.8 million noncash gain related to the change in our
     ownership of PAA resulting from PAA's 1999 public offering of common units.
     For 1998, includes a $60.8 million noncash gain recognized upon the
     formation of PAA. See Item 7. - "Management's Discussion and Analysis of
     Financial Condition and Results of Operations".
(3)  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 Corporation 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".
(4)  For the year ended December 31, 2000, this amount includes $4.4 million of
     previously deferred net gains from terminated interest rate swaps
     recognized as a result of debt extinguishment.
(5)  In November 1999, we discovered that a former employee of PAA had engaged
     in unauthorized trading activity, resulting in losses of approximately
     $174.0 million, which includes 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 $8.0 million
     charge for litigation related to the unauthorized trading losses. See Item
     1. - "Business - Unauthorized Trading Losses".
(6)  General and administrative expense for 2000 includes a $5.0 million charge
     to reserve for potentially uncollectible accounts receivable. See Item 7. -
     "Management's Discussion and Analysis of Financial Condition and Results of
     Operations - Results of Operations".
(7)  Includes a $173.9 million pre-tax ($109.0 million after tax) noncash charge
     related to a writedown of the capitalized costs of our proved crude oil and
     natural gas properties due to low crude oil prices at December 31, 1998.
(8)  Represents charge related to the settlement of two lawsuits filed in 1992
     and 1993.
(9)  Relates to the early redemption and refinancing of PAA debt in 2000 and
     early redemption of PAA debt in 1999 and of our 12% Senior Subordinated
     Notes in 1996.
(10) Represents the cumulative effect adjustment as a result of the adoption of
     SEC Staff Accounting Bulletin 101 - "Revenue Recognition in Financial
     Statements" ("SAB 101"). See Item 7. - "Management's Discussion and
     Analysis of Financial Condition and Results of Operations - Recent
     Accounting Pronouncements". The effect of this change in prior periods is
     deminimus.
(11) Represents net cash provided by operating activities after minority
     interest but before changes in assets and liabilities and other noncash
     items.
(12) EBITDA means earnings before interest, taxes, depreciation, depletion and
     amortization. Adjusted EBITDA also excludes unauthorized trading losses,
     noncash compensation expense, restructuring expense, gain on unit
     offerings, gains on linefill and pipeline, allowance for accounts
     receivable, extraordinary loss from extinguishment of debt and cumulative
     effect of accounting change. Adjusted EBITDA is not a measurement presented
     in accordance with generally accepted accounting principles ("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.
(13) 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. - "Midstream
     Acquisitions and Dispositions - All American Pipeline Linefill Sale and
     Asset Disposition".

                                       39
<PAGE>

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

GENERAL

  We are an independent energy company that is engaged in two related lines of
business within the energy sector industry. Our first line of business, which we
refer to as "upstream", acquires, exploits, develops, explores and produces
crude oil and natural gas. Our second line of business, which we refer to as
"midstream", is engaged in the 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". We conduct this second line of
business through our majority ownership in PAA. For financial statement
purposes, the assets, liabilities and earnings of PAA are included in our
consolidated financial statements, with the public unitholders' interest
reflected as a minority interest.

RECENT DEVELOPMENTS

  In connection with our business strategy, we continually review strategic
options or proposals relating to mergers, consolidations and acquisition
opportunities involving us and our subsidiaries. We have publicly announced that
we are evaluating strategic restructuring alternatives intended to optimize the
value and value-creating ability of each of our upstream and midstream business
segments. The alternatives to be evaluated 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 units of PAA 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.

  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 of PAA 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 this amount was recognized in 1998 and the
remainder in 1999. In 2000, we recognized an additional $8.0 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 PAA's
trading policies. See Item 3. - "Legal Proceedings".

RESULTS OF OPERATIONS

  In the fourth quarter of 2000, we adopted SAB 101. As a result, we record
revenue from crude oil production in the period it is sold as opposed to when it
is produced and carry any unsold production as inventory valued at historical
cost. The total effect of implementing SAB 101 was to reduce reported sales
volumes by 144,000 barrels for 2000 and net income by $175,000, including a
$121,000 reduction for the cumulative effect of prior years. The effect of this
change in accounting for crude oil inventories on prior periods is deminimus.

Also 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 now report these
activities as gross marketing, transportation, storage and terminalling revenues
and expenses. Marketing, transportation, storage and terminalling revenues and
expenses for all periods presented have been reclassified to reflect this
adoption, with no effect on earnings.

 Analysis of Three Years Ended December 31, 2000.

  For the year ended December 31, 2000, we reported net income of $40.8 million,
or $1.46 per share ($1.39 per diluted share) on total revenue of $6.6 billion as
compared to a net loss of $25.3 million, or $2.05 per share on total revenue of
$10.9 billion in 1999. For the year ended December 31, 1998, we reported a net
loss of $62.3 million or $3.99 per share on total revenue of $3.6 billion.

                                       40
<PAGE>

  The reported 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;
 .  $8.0 million charge for litigation related to the unauthorized trading
   losses;
 .  $4.4 million of previously deferred net gains on interest rate swap
   terminations recognized due to the early extinguishment of debt;
 .  a $5.0 million reserve for potentially uncollectible accounts receivable;
 .  an extraordinary loss of $5.0 million related to the early extinguishment of
   debt (net of minority interest and tax benefit);
 .  amortization of $4.6 million of debt issue costs associated with facilities
   put in place during the fourth quarter of 1999;
 .  $2.7 million of noncash compensation expense; and
 .  $0.9 million gain recognized upon the transfer of 69,444 of our units in PAA
   to employees of the general partner upon the vesting of transaction unit
   grants.

1999
 .  $166.4 million of unauthorized trading losses;
 .  a $16.5 million gain on the sale of crude oil linefill;
 .  a $6.0 million after-tax gain ($9.8 million pre-tax) related to the sale of
   units by PAA;
 .  restructuring expense of $1.4 million;
 .  $1.0 million of noncash compensation expense; and
 .  an extraordinary loss of $0.5 million related to the early extinguishment of
   debt (net of minority interest and tax benefit).

1998
 .  $109.0 million after-tax ($173.9 million pre-tax) reduction in carrying cost
   of oil and natural gas properties due to low crude oil prices at December 31,
   1998;
 .  a $37.1 million after-tax ($60.8 million pre-tax) gain associated with the
   initial public offering of PAA; and
 .  $7.1 million of unauthorized trading losses.

  Excluding the items listed above, we would have reported net income of
approximately $35.8 million and $18.2 million in 2000 and 1999, respectively.
Adjusted EBITDA increased 25% in 2000 to $179.2 million from the $139.1 million
reported in 1999 and 117% from the $80.3 million reported in 1998. Cash flow
from operations (net income before noncash items), also excluding the items
listed above, was $100.6 million, $70.4 million and $42.0 million in 2000, 1999
and 1998, respectively. Adjusted EBITDA also excludes the items discussed above.

  Oil and natural gas sales. Oil and natural gas sales were $149.3 million in
2000, an increase of $33.1 million over 1999 due to higher product prices and
increased production volumes which contributed approximately $28.7 million and
$4.4 million to the increase, respectively. Oil and natural gas revenues
increased to $116.2 million in 1999 as compared to $102.8 million in 1998 due to
higher product prices and increased production volumes, which contributed
approximately $7.5 million and $6.0 million to the increase, respectively.

  Marketing, transportation, storage and terminalling revenues. Marketing,
transportation, storage and terminalling revenues increased to $6.4 billion from
$10.8 billion and $3.5 billion in 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. See "Midstream Results".

  Gain on PAA unit offerings. In 1999, we recognized a pre-tax gain of $9.8
million ($6.0 million after-tax) in connection with PAA's October 1999 public
offering. The gain is the result of an increase in the book value of our equity
in PAA to reflect our proportionate share of the underlying net assets of PAA
due to the sale of the units. We held approximate interests of 59% and 54%
before and after this offering, respectively. During 1998, we recognized a pre-
tax gain of approximately $60.8 million ($37.1 million after-tax) in connection
with the formation of PAA. The gain was net of approximately $9.2 million of
formation related expenses consisting primarily of amounts due to certain key
employees in connection with the

                                       41
<PAGE>

successful formation of PAA, debt prepayment penalties and legal fees. The gain
is the result of an increase in the book value of our equity in PAA to reflect
our proportionate share of the underlying net assets of PAA due to the sale of
units in the initial public offering. PAA may in the future issue additional
units in public or private sales if it needs additional capital and if market
conditions are favorable. Such sales could reduce our ownership in PAA and could
generate additional gains.

  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 the outstanding debt of
PAA. 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.

  Transaction grant gain. Upon the transfer of 69,444 of our units in PAA to
employees of the general partner, a gain of $0.9 million was recognized in the
first quarter of 2000, which represented the difference between the market price
on the date of vesting and our basis in the units.

  Production expenses. Total production expenses increased to $62.1 million from
$55.6 million and $50.8 million in 1999 and 1998, respectively, primarily due to
increased production volumes resulting from our acquisition and exploitation
activities, as well as increased per unit costs.

  Marketing, transportation, storage and terminalling expenses. Marketing,
transportation, storage and terminalling expenses increased to $6.3 billion from
$10.7 billion and $3.4 billion in 1999 and 1998, respectively, due to the
reasons discussed above for marketing, transportation, storage and terminalling
revenues.

  Unauthorized trading losses. As previously discussed, we recognized losses of
approximately $8.0 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 $50.8
million for the year ended December 31, 2000, compared to $31.4 million and
$10.8 million for 1999 and 1998, respectively. Our upstream and midstream
activities accounted for approximately $2.1 million and $17.3 million,
respectively, of the increase from 1999 to 2000 and $2.3 million and $18.3
million, respectively, of the increase from 1998 to 1999.

  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 $2.7 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 the employees the right to earn ownership in common units of PAA owned
by Plains All American Inc. The units vest over a three-year period subject to
PAA paying distributions on the common and subordinated units. These amounts are
included in general and administrative expense on the Consolidated Statements of
Operations and are attributable to the midstream segment.

  Restructuring expense. A $1.4 million restructuring charge, primarily
associated with severance-related expenses of 24 employees who were terminated,
was incurred by PAA in 1999. Approximately $1.1 million of these costs are
included in marketing, transportation, storage and terminalling expenses and
approximately $0.3 million are included general and administrative expenses. As
of December 31, 1999, all severance costs were paid and the terminated employees
were not employed by PAA.

  Depreciation, depletion and amortization. Total depreciation, depletion and
amortization ("DD&A") was $47.2 million, $37.0 million and $31.0 million for the
years ended December 31, 2000, 1999 and 1998, respectively. Our upstream and
midstream activities accounted for approximately $2.9 million and $7.3 million,
respectively, of the increase from 1999 to

                                       42
<PAGE>

2000. The $6.0 million increase from 1998 to 1999 is comprised of a $6.0 million
decrease in upstream DD&A and a $12.0 million increase in midstream DD&A.

  Reduction in carrying cost of oil and natural gas properties. In 1998, we
incurred an impairment of our oil and natural gas properties due to low crude
oil prices at December 31, 1998. Under full-cost accounting rules, unamortized
costs of proved oil and natural gas properties are subject to a ceiling, which
limits such costs. At December 31, 1998, the capitalized costs of our proved oil
and natural gas properties exceeded this limit and we reduced the carrying cost
of those properties by $109.0 million after tax ($173.9 million pre-tax).

  Interest expense. Interest expense, net of capitalized interest, for 2000
increased to $55.8 million as compared to $46.4 million in 1999 and $35.7
million in 1998. The increase in 2000 is primarily due to increased interest
rates. The increase in 1999 is due to (1) interest associated with the debt
incurred for the Scurlock and West Texas Gathering System acquisitions, (2)
interest for a full year on debt outstanding from the All American Pipeline
acquisition, (3) an increase in interest related to hedged inventory
transactions (4) higher debt levels related to our acquisition, exploitation,
development and exploration activities and (5) higher interest rates. During
2000, 1999 and 1998, we capitalized $4.4 million, $4.4 million and $3.7 million
of interest, respectively.

  Provision (benefit) for income taxes. For the year ended December 31, 2000, we
recognized a deferred tax provision of $24.6 million and a current tax provision
of $1.0 million. For the year ended December 31, 1999, we recognized a deferred
tax benefit of $20.5 million. For the year ended December 31, 1998, we
recognized a deferred tax provision of $45.9 million and a current tax provision
of $0.9 million. At December 31, 2000, we have a net deferred tax asset of $47.9
million, primarily attributable to net operating loss carryforwards. The minimum
amount of future taxable income necessary to utilize the net operating loss
carryforwards is $183.9 million. Based on current levels of pre-tax income,
excluding nonrecurring items, management believes that it is more likely than
not that we will generate taxable income from operations sufficient to realize
the deferred tax asset.

  Early extinguishment of debt. During 2000, we recognized extraordinary losses,
consisting primarily of unamortized debt issue costs, totaling $5.0 million (net
of minority interest of $7.0 million and deferred tax of $3.2 million) related
to the permanent reduction of the All American Pipeline, L.P. term loan facility
and the refinancing of PAA's credit facilities. In addition, interest and other
income for the year ended December 31, 2000 includes $4.4 million of previously
deferred net gains from terminated interest rate swaps as a result of the debt
extinguishment. The extraordinary item of $0.5 million (net of minority interest
of $.07 million and deferred tax of $0.3 million) in 1999 relates to the write-
off of certain debt issue costs and penalties associated with the prepayment of
debt.

 Upstream Results

  The following table sets forth certain of our upstream operating information
for the periods presented.

<TABLE>
<CAPTION>
                                                               Year Ended December 31,
                                                      -----------------------------------------
                                                         2000           1999            1998
                                                      ----------     ----------     -----------
                                                        (in thousands, except per unit data)
<S>                                                   <C>            <C>            <C>
Average Daily Production Volumes:
  Barrels of oil equivalent
    Onshore California (approximately 91% oil)             15.4           15.6            13.8
    California OCS (100% oil)                               4.1            2.2               -
    Gulf Coast (100% oil)                                   1.9            2.6             4.8
    Illinois Basin (100% oil)                               2.8            3.0             3.5
                                                     ----------     ----------     -----------
      Total (approximately 94% oil)                        24.2           23.4            22.1
                                                     ==========     ==========     ===========
Unit Economics:
  Average sales price per BOE                           $ 16.85        $ 13.61         $ 12.73
  Production expense per BOE                               7.01           6.51            6.29
                                                     ----------     ----------     -----------
  Gross margin per BOE                                     9.84           7.10            6.44

  Upstream G&A expense per BOE                             1.12           0.91            0.68

                                                     ----------     ----------     -----------
  Gross profit per BOE                                   $ 8.72         $ 6.19          $ 5.76

                                                     ==========     ==========     ===========

</TABLE>

                                       43
<PAGE>

  Upstream results were affected by of the adoption of SAB 101. As a result of
SAB 101, we record revenue from crude oil production in the period it is sold as
opposed to when it is produced and carry any unsold production as inventory
valued at historical cost. The total effect of SAB 101 is to reduce reported
sales volumes by 144,000 barrels for 2000 and net income for the year by
$175,000, including a $121,000 reduction for the cumulative effect of prior
years.

  Total oil equivalent production increased approximately 3% to an average of
24,200 BOE per day from the 1999 level of 23,400 BOE per day and 10% above the
1998 level of 22,100 BOE per day. The volume increase in 2000 is attributable to
a full year of production from the Point Arguello Unit, which we purchased from
Chevron in July 1999. Current year production from this area was negatively
impacted by approximately 400 BOE per day due to the reversion to a lower net
revenue interest effective July 1, 2000. The volume increase in 1999 is
primarily associated with our ongoing acquisition and exploitation activities,
offset somewhat by decreased production from certain of our other properties.
Net daily production from our onshore California properties averaged 15,400 BOE
per day in 2000 compared to 15,600 BOE per day in 1999. The slight decrease is
primarily due to natural decline. Net daily production for our Gulf Coast
properties averaged approximately 1,900 BOE per day in 2000, compared to 2,600
BOE per day in 1999 and 4,800 BOE per day in 1998. The Gulf Coast production
decrease is due to the effects of natural decline. Net daily production in the
Illinois Basin averaged 2,800 BOE per day during 2000, compared to 3,000 BOE per
day in 1999. The decrease is due to lower water injection rates, natural decline
and the high demand for completion units which has delayed completion of newly
drilled wells and routine well servicing.

  Our product price averaged $16.85 per BOE in 2000, 24% and 33% higher than the
price received in 1999 and 1998, respectively. Our product price represents a
combination of fixed and floating price arrangements, typically tied to a
benchmark price index and subjected to discounts for location and quality
differentials. The price index is the NYMEX benchmark WTI crude oil price, which
averaged $30.25 per barrel in 2000, $19.25 per barrel in 1999, and $14.43 per
barrel in 1998. The discount to NYMEX for our crude oil production averaged
$4.63 per barrel during 2000. Our average product prices also include the
effects of hedging transactions such as financial swap and collar arrangements
and futures transactions. These transactions had the effect of decreasing the
overall average price we received (relative to the price we would have received
in the absence of hedging) by $8.96 per BOE and $1.30 per BOE in 2000 and 1999,
respectively, and increasing the price by $2.98 per BOE in 1998. We maintained
hedges on approximately 82% of our crude oil production throughout 2000 at an
average NYMEX WTI crude oil price of approximately $18.47 per barrel. We
routinely hedge a portion of our crude oil production. See "Outlook" and Item
7a. - "Quantitative and Qualitative Disclosures about Market Risk".

  Upstream unit gross margin (well-head revenue less production expenses) for
2000 was $9.84 per BOE, compared to $7.10 per BOE in 1999 and $6.44 per BOE in
1998. Average unit production expenses were $7.01 per BOE, $6.51 per BOE and
$6.29 per BOE in 2000, 1999, and 1998, respectively. Total production expenses
were $62.1 million, $55.6 million and $50.8 million in 2000, 1999 and 1998,
respectively. The increase in aggregate production expenses from 1999 to 2000 is
primarily attributable to a full year of California OCS production, increased
gas fuel costs, as well as general upward pressure on costs throughout the
service industry. Factors contributing to the higher year to year unit
production costs include fixed costs associated with properties which had
decreased production, higher production related taxes, environmental compliance
and general upward pressure on costs throughout the service industry.

  Unit general and administrative expense increased to $1.12 per BOE in 2000
compared to $0.91 per BOE during 1999 and $0.68 per BOE during 1998. Total
upstream general and administrative expense was $9.9 million, $7.8 million and
$5.5 million in 2000, 1999 and 1998, respectively. The increase in 2000 as
compared to 1999 is primarily attributable to increased personnel costs,
decreased capitalized general and administrative expense related to our
acquisitions, exploitation and development activities and expenses related the
strategic restructuring that we announced in November 2000. The increase in 1999
as compared to 1998 is primarily attributable to increased personnel costs
(approximately $0.8 million), expenses related to our Year 2000 computer
readiness project (approximately $0.4 million), and legal expenses
(approximately $0.4 million).

  Total upstream DD&A was $22.5 million, $19.6 million and $25.6 million in
2000, 1999 and 1998, respectively. The increase in 2000 as compared to 1999 is
due to higher production volumes and a higher per unit DD&A rate ($2.31 per BOE
in 2000 versus $2.13 per BOE in 1999). The decrease in 1999 as compared to 1998
is primarily due to a lower per unit DD&A rate ($2.13 per BOE in 1999 versus
$3.00 per BOE in 1998). These amounts exclude the reduction in the carrying cost
of our oil and natural gas properties in 1998.

                                       44
<PAGE>

  Midstream Results

  Gross margin from our midstream activities, excluding the unauthorized trading
losses was $133.0 million, $107.7 million and $38.4 million for the years ended
December 31, 2000, 1999 and 1998, respectively. An analysis of these results is
discussed below. The following table sets forth certain of our midstream
operating information for the periods presented (in thousands):

<TABLE>
<CAPTION>
                                                   Year Ended December 31,
                                        -------------------------------------------
                                             2000            1999          1998
                                        -------------   -------------  ------------
<S>                                     <C>             <C>            <C>
Operating Results:
  Gross margin
    Pipeline                              $ 51,787        $ 56,864       $ 16,490
    Terminalling and storage
      and gathering and marketing           81,242          50,826         21,871
    Unauthorized trading losses             (6,963)       (166,440)        (7,100)
                                        ----------      ----------      ---------
      Total                                126,066         (58,750)        31,261
  General and administrative expense       (40,871)        (23,599)        (5,297)
                                        ----------      ----------      ---------
  Gross profit                            $ 85,195       $ (82,349)      $ 25,964
                                        ==========      ==========      =========
Average Daily Volumes (barrels):
  Pipeline Activities:
    All American
      Tariff activities                         74             101            113
      Margin activities                         60              56             50
    Other                                      107              61              -
                                        ----------      ----------       --------
    Total                                      241             218            163
                                        ==========      ==========       ========
  Lease gathering                              236             239             88
  Bulk purchases                                28             138             98
                                        ----------      ----------       ---------
     Total                                     264             377            186
                                        ==========      ==========      ==========
  Terminal throughput                           67              83             80
                                        ==========      ==========      ==========
  Storage leased to third parties,
    monthly average volumes                  1,657           1,975          1,150
                                        ==========      ==========      ==========
</TABLE>

  Pipeline Operations. Gross margin from pipeline operations was $51.8 million
for the year ended December 31, 2000, compared to $56.9 million for 1999 and
$16.5 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 $33.5 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, $23.0 million and $6.4 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 California OCS, 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.

                                       45
<PAGE>

  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 $81.2
million for the year ended December 31, 2000, reflecting a 60% increase over the
$50.8 million reported for 1999 and a 271% increase over the $21.9 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 $5.9 billion, $10.0
billion and $3.2 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 236,000 barrels per day in 2000, 239,000
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
primarily 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 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 and $2.1 million, respectively, 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 1.7
million, 2.0 million and 1.2 million barrels per month for the same periods.

  Midstream General and Administrative. General and administrative expenses were
$40.9 million for the year ended December 31, 2000, compared to $23.6 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.

  We expect midstream 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 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.

  Midstream Depreciation and Amortization. Depreciation and amortization expense
was $24.7 million in 2000, $17.4 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.

                                       46
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

  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
PAA's 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 PAA's stated
policy of maintaining a strong capital structure by funding acquisitions with a
balance of debt and equity, PAA intends to refinance a portion of its 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 $20.3 million and availability on our upstream and midstream
credit facilities of $197.7 million and $80.0 million, respectively. In
connection with the previously discussed Canadian acquisitions, PAA's existing
credit facilities will be 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, PAA intends to refinance
a portion of its 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.

                                       47
<PAGE>

 Cash Flows

<TABLE>
<CAPTION>
                                                Year Ended December 31,
                                      ------------------------------------------------
                                          2000             1999             1998
                                      --------------   --------------  ---------------
                                                     (in millions)
<S>                                   <C>              <C>             <C>
Cash provided by (used in):
  Operating activities                     $ 35.9          $ (76.0)          $ 37.6

  Investing activities                      130.2           (266.4)          (483.4)

  Financing activities                     (229.2)           404.0            448.6

</TABLE>

  Operating Activities. Net cash provided by operating activities in 2000
totaled $35.9 million compared to net cash used in operating activities of $76.0
million in 1999.  The net increase is attributable to increased cash flows from
our upstream and midstream activities, offset somewhat by amounts paid in the
current year for the 1999 unauthorized trading losses as well as increases in
crude oil inventory and linefill. Midstream cash flows increased in the current
year due to a full year of results from the Scurlock and West Texas gathering
system acquisitions as well as increased margins due to the strong crude oil
market. Increased upstream cash flows are attributable to higher oil prices and
increased production. Net cash used in operating activities in 1999 resulted
from the unauthorized trading losses. The losses were partially offset by
increased midstream margins due to the Scurlock and West Texas gathering system
acquisitions and higher crude oil prices and increased volumes associated with
our ongoing upstream acquisition and exploitation activities.

  Investing Activities. In 2000 net cash provided by investing activities
resulted from the proceeds from assets sales of $224.3 million.  During 2000
investing activities included expenditures of $12.2 million for crude oil
pipeline, gathering and terminal costs and $78.7 million for acquisition,
exploration and development costs. Net cash used in investing activities for
1999 included approximately $176.9 million for midstream acquisitions, primarily
for the Scurlock and West Texas gathering system acquisitions, approximately
$12.5 million for midstream capital costs and $77.9 for upstream acquisition,
exploration, exploitation and development costs. 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 and $80.3 million
for acquisition, exploration, exploitation and development costs.

  Financing activities. Cash used in financing activities in 2000 included a net
reduction in long and short term debt of $158.0 million, expenditures of $23.6
million for the purchase of 1.3 million shares of treasury stock, $13.4 million
in preferred stock dividends and $29.4 million in distributions to PAA
unitholders. Cash provided by financing activities in 1999 was generated
primarily from net issuances of (1) $50.0 million of Series F Preferred Stock
(2) $50.8 million in PAA common units and (3) $325.2 million of short-term and
long-term debt.  Financing activities for 1999 also included dividend payments
of approximately $4.2 million on the Series E Preferred Stock and distributions
to PAA unitholders of $22.2 million. Cash provided by financing activities
during 1998 included net issuances of (1) $138.8 million of short-term and long-
term debt, (2) $241.7 million of common units in connection with PAA's initial
public offering and (3) $85.0 million in preferred stock.

  In December 2000, we exchanged, redeemed or converted all of the outstanding
shares of our Series G Preferred Stock. We exchanged 169,571 shares of the
Series G Preferred for an equivalent number of a new Series H Preferred Stock,
plus a cash payment in an amount equal to accrued and unpaid dividends. We
redeemed 213 shares at 105% of stated value plus accrued and unpaid dividends
and converted 1,825 shares of Series G Preferred Stock into 62,226 shares of
common stock. Each share of the Series H Preferred Stock is convertible into
33.33 shares of common stock. The Series H Preferred Stock, unlike the Series G
Preferred Stock, does not bear a dividend and does not contain a mandatory
redemption feature.

  In June 2000, our Board of Directors authorized the repurchase of up to one
million shares of our common stock and in November the Board authorized
repurchase of an additional one million shares.  At December 31, 2000 we had
repurchased 1.3 million shares for a total of $23.6 million and through February
28, 2001 we had repurchased a total of 1.6 million shares for total
consideration of $30.6 million, or an average price of $18.83 per share.

 Capital Expenditures

  We have made and will continue to make substantial capital expenditures for
the acquisition, exploitation, development, exploration and production of crude
oil and natural gas reserves. Historically, we have financed these expenditures
primarily with cash generated by operations, bank borrowings and the sale of
subordinated notes, common stock and preferred stock. We intend to make
aggregate capital expenditures of approximately $127.0 million in 2001,
including approximately $120.0 million on the development and exploitation of
our upstream properties, and approximately $7.0 million for midstream
activities. In addition, we intend to continue to pursue the acquisition of
underdeveloped producing properties and midstream

                                       48
<PAGE>

acquisition opportunities. We believe that we will have sufficient cash from
operating activities and borrowings under the revolving credit facility to fund
our upstream capital expenditures. We plan to fund the midstream capital
expenditures through working capital, cash flow, and draws under PAA's revolving
credit facility and public and private debt and equity offerings.

 Commitments

  The aggregate amounts of maturities of all long-term indebtedness for the next
five years at December 31, 2000 are: 2001 - $0.5 million, 2002 - $2.8 million,
2003 - $9.6 million, 2004 - $9.6 million, and 2005 - $326.8 million. These
amounts consist principally of amounts due under our revolving credit facilities
and subordinated notes and reflect the February 2001 amendments to PAA's
revolving credit facilities. Historically, we have renewed and/or extended the
revolving credit portion of our credit facilities prior to commencing scheduled
payments.

  PAA will distribute 100% of its available cash within 45 days after the end of
each quarter to unitholders of record, and to us. 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.

  In connection with its crude oil marketing, PAA provides 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, PAA had outstanding letters of credit of
approximately $59.7 million. Such letters of credit are secured by PAA's crude
oil inventory and accounts receivable.

  Although we obtained environmental studies on our properties in California,
the Sunniland Trend and Illinois Basin, and we believe that such properties have
been operated in accordance with standard oil field practices, certain of the
fields have been in operation for approximately 90 years, and current or future
local, state and federal environmental laws and regulations may require
substantial expenditures to comply with such rules and regulations.

  Consistent with normal industry practices, substantially all of our crude oil
and natural gas leases require that, upon termination of economic production,
the working interest owners plug and abandon non-producing wellbores, remove
tanks, production equipment and flow lines and restore the wellsite. We have
estimated that the costs to perform these tasks are approximately $11.0 million,
net of salvage value and other considerations. Such estimated costs are
amortized to expense through the unit-of-production method as a component of
accumulated depreciation, depletion and amortization. Results from operations
for 2000, 1999 and 1998 include $0.5 million, $0.5 million and $0.8 million,
respectively, of expense associated with these estimated future costs. For
valuation and realization purposes of the affected crude oil and natural gas
properties, these estimated future costs are also deducted from estimated future
gross revenues to arrive at the estimated future net revenues and the
Standardized Measure disclosed in the accompanying Consolidated Financial
Statements.

  As is common within the industry, we have entered into various commitments and
operating agreements related to the exploration and development of and
production from proved oil and natural gas properties and 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.

                                       49
<PAGE>

 Credit Facilities

  Amounts borrowed under our credit agreements were as follows at the dates
indicated (in thousands):

<TABLE>
<CAPTION>
                                                                                  December 31,
                                                                           --------------------------
                                                                             2000              1999
                                                                           ---------        ---------
<S>                                                                         <C>              <C>
Revolving credit facility                                                   $ 27,300         $137,300
Plains Marketing, L.P. revolving credit facility                             320,000                -
Plains Marketing, L.P. letter of credit and hedged inventory facility          1,300                -
PAA bank credit agreement                                                          -          225,000
Plains Scurlock bank credit agreement                                              -           85,100
PAA letter of credit and borrowing facility                                        -           13,719
PAA secured term credit facility                                                   -           45,000
                                                                            --------         --------
                                                                            $348,600         $506,119
                                                                            ========         ========
</TABLE>

  We have a $225.0 million revolving credit facility with a group of banks. The
revolving credit facility is guaranteed by all of our upstream subsidiaries and
is collateralized by our upstream oil and natural gas properties and those of
the guaranteeing subsidiaries and the stock of all the upstream subsidiaries.
The borrowing base under the revolving credit facility at December 31, 2000, is
$225.0 million and is subject to redetermination from time to time by the
lenders in good faith, in the exercise of the lenders' sole discretion, and in
accordance with customary practices and standards in effect from time to time
for crude oil and natural gas loans to borrowers similar to our company. Our
borrowing base may be affected from time to time by the performance of our oil
and natural gas properties and changes in oil and natural gas prices. We incur a
commitment fee of 3/8% per annum on the unused portion of the borrowing base. In
addition, we pay a fee of 1 3/8% per annum of the face amount of letters of
credit that are issued under our revolving credit facility. The revolving credit
facility, as amended, terminates on July 1, 2002, at which time the remaining
outstanding balance converts to a term loan which is repayable in twelve equal
quarterly installments commencing October 1, 2002, with a final maturity of July
1, 2005. The revolving credit facility bears interest, at our option, of either
LIBOR plus 1 3/8% or Base Rate (as defined therein). At December 31, 2000,
letters of credit of $0.6 million were outstanding under the revolving credit
facility.

  The revolving credit facility contains covenants which, among other things,
prohibit the payment of cash dividends on common stock, limit repurchases of
common stock, limit the amount of consolidated debt, limit our ability to make
certain loans and investments and provide that we must maintain a specified
relationship between current assets and current liabilities. We are currently in
compliance with the covenants contained in the revolving credit facility. At
December 31, 2000, we could have borrowed the full $225.0 million available
under the revolving credit facility.

  In May 2000, PAA 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, PAA's 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 PAA
to borrow an additional $130.0 million under the terms of the senior secured
revolving credit facility to consummate the Canadian acquisitions. PAA has an
underwritten commitment, subject to certain conditions, for the $130.0 million.

  PAA's bank credit agreements currently consist of:

  .  a $500.0 million senior secured revolving credit facility, of which $492.0
     million is currently available, which is secured by substantially all of
     PAA's assets and matures in April 2005. No principal is scheduled for
     payment prior to maturity. The revolving credit facility bears interest at
     PAA's option at either the base rate, as defined, plus an applicable
     margin, or LIBOR plus an applicable margin. PAA incurs 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 which has been hedged against future price risk. The
     letter of credit facility is secured by substantially all of PAA's assets
     and has a sublimit for cash borrowings of $100.0 million to purchase crude
     oil which 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 which is determined monthly based on certain of PAA's
     current assets and current liabilities, primarily accounts receivable and
     accounts payable related to the purchase and sale of crude oil. At December
     31, 2000, $57.9 million in letters of credit were outstanding under the
     letter of credit and borrowing facility.

                                       50
<PAGE>

  PAA's 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 PAA's 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.

  PAA's bank credit agreements treat a change of control as an event of default
and also requires it 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 PAA's 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 PAA is in compliance with its bank
credit agreements, they do not restrict its ability to make distributions of
"available cash" as defined in the partnership agreement. PAA is currently in
compliance with the covenants contained in its credit agreements. Under the most
restrictive of these covenants, at December 31, 2000, PAA could have borrowed up
to $386.4 million under its secured revolving credit facility.

 Contingencies

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

                                       51
<PAGE>

OUTLOOK

  Our upstream activities are affected by changes in crude oil prices, which
historically have been volatile. Although we have routinely hedged a substantial
portion of our crude oil production and intend to continue this practice,
substantial future crude oil price declines would adversely affect our overall
results, and therefore our liquidity. Furthermore, low crude oil prices could
affect our ability to raise capital on favorable terms. Decreases in the prices
of crude oil and natural gas have had, and could have in the future, an adverse
effect on the carrying value of our proved reserves and our revenues,
profitability and cash flow To manage our exposure to commodity price risk, our
upstream business routinely hedges a portion of its crude oil production. For
2001, we have entered into various arrangements, using a combination of swaps,
collars and purchased puts and calls, which will provide for us to receive an
average minimum NYMEX price of approximately $23.00 per barrel on 21,500 barrels
per day with full market price participation up to an average of $27.00 per
barrel. We then have further upside participation on approximately 32% of those
hedged barrels to $30.00 per barrel, upside participation on 55% of hedged
barrels beyond a NYMEX price of $30.00 and 100% upside participation on hedged
barrels above a NYMEX price of $35.90. For example, if the NYMEX index averages
$35.00 during 2001, we will receive $31.30 per barrel, if the NYMEX index
averages 27.00, we will receive $27.00 per barrel, if the NYMEX index averages
$23.00 per barrel, we will receive $24.50 per barrel, and if the NYMEX index
were to fall to $15.00 per barrel we would receive approximately $21.83 per
barrel. For 2002, we have entered into various arrangements that provide for us
to receive an average minimum NYMEX price of $23.25 per barrel on 16,000 barrels
per day with full market price participation on 25% of the hedged barrels up to
$35.00 per barrel and 100% upside participation on approximately 80% of the
hedged barrels beyond $35.00. Location and quality differentials attributable to
our properties and the cost of the hedges are not included in the foregoing
prices for 2001 and 2002. Because of the quality and location of our crude oil
production, these adjustments will reduce our net price per barrel. The cost of
the hedges is included in our balance sheet at December 31, 2000. Our management
intends to continue to maintain hedging arrangements for a significant portion
of our production. These contracts may expose us to the risk of financial loss
in certain circumstances. Our hedging arrangements provide us protection on the
hedged volumes if crude oil prices decline below the prices at which these
hedges are set. But ceiling prices in our hedges may cause us to receive less
revenue on the hedged volumes than we would receive in the absence of hedges.
See Item 7a. - "Quantitative and Qualitative Disclosures About Market Risk".

  Higher crude, natural gas and hydrocarbon product prices have resulted in an
increase in operating costs for natural gas, diesel and electricity consumed by
operations, and we expect these costs may rise or fall depending on the
volatility of the crude, natural gas and electrical power markets. On March 27,
2001, the California Public Utilities Commission proposed a $0.04 per kilowatt
hour increase in electric rates by making permanent a $0.01 per kilowatt hour
temporary increase that was effective on January 1, 2001 and further increasing
the rate by $0.03 per kilowatt hour. The rate increase, which will affect
certain of our onshore properties in California, will increase our upstream
production expenses. In addition, as a result of consolidation among service and
supply companies and increasing demand for rigs, supplies and services, it is
anticipated there will be continued upward pressure on operating expenses and
capital costs.

  Certain of our operations in California that have interruptible electrical
contracts have been adversely impacted by electrical service interruptions. We
estimate that our oil and gas production for 2000 and the first quarter of 2001
was adversely affected by approximately 43,000 BOE and 45,000 BOE, respectively,
as a result of such interruptions. Although under recent regulatory rulings we
believe that our operations will only be affected if rolling blackouts occur and
we have made operational changes to mitigate the effects of electrical
interruptions, there can be no assurance that our operations will not be
adversely impacted in the future by the California power market.

  Our midstream operations will also 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.

  As is common with most merchant activities, our ability to generate a profit
on our midstream 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.

  A significant portion of the gross margin of PAA is derived from the Santa
Ynez and Point Arguello fields located California OCS. 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, we are
conducting additional drilling and other activities

                                       52
<PAGE>

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.

  As previously discussed, our future results will also be affected by natural
decline in our producing oil and natural gas properties and declines in
California OCS production transported on the All American Pipeline.

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 stockholders' equity. 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 net-of-tax and minority interest cumulative effect gain of $4.5
million in other comprehensive income and a net-of-tax and minority interest
cumulative effect charge of $2.0 million to earnings to recognize at fair value
all derivative instruments that were designated as cash flow hedging
instruments. Correspondingly, assets have been increased by $14.2 million and
liabilities and minority interest have been increased by $11.7 million.
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 equity through comprehensive income.

                                       53
<PAGE>

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 our 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 commodity
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):


<TABLE>
<CAPTION>

                                                             December 31,
                                        ----------------------------------------------------
                                                  2000                        1999
                                        -------------------------    -----------------------
                                                        Effect of                  Effect of
                                                           10%                        10%
                                           Fair           Price          Fair        Price
                                          Value         Decrease        Value      Decrease
                                        -----------   -----------    -----------  ----------
<S>                                     <C>           <C>            <C>          <C>
Crude oil:
  Futures contracts                       $  (9.4)      $  6.0         $    -        $ (2.8)
  Swaps and options contracts                17.3        (13.0)         (22.0)         (6.2)
</TABLE>

  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 and 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 prices 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 oil prices, the fair
value of our derivative portfolio would typically change less than that shown in
the table due to lower volatility in out-month prices.

  We have entered into various arrangements, using a combination of swaps,
collars and purchased puts and calls, to fix the NYMEX crude oil spot price for
a significant portion of our crude oil production. On December 31, 2000, these
arrangements provided for a NYMEX crude oil price of approximately $23.00 per
barrel on 21,500 barrels per day from January 1, 2001, through December 31,
2001, with full market price participation up to an average of $27.00 per
barrel. For 2002, we have entered into various arrangements that provide for us
to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000
barrels per day with full market price participation up to an average of $24.90
per barrel. Location and quality differentials attributable to our properties
and the cost of the hedges are not included in the foregoing prices. Because of
the quality and location of our crude oil production, these adjustments will
reduce our net price per barrel. The agreements provide for monthly settlement
based on the differential between the agreement price and the actual NYMEX
price. Gains or losses are recognized in the month of related production and are
included in crude oil and natural gas sales. Such contracts resulted in a
reduction of revenues of $79.4 million and $11.1 million for the years ended
December 31, 2000 and 1999, respectively. At December 31, 2000, we had an
unrealized gain of $17.3 million with respect to such contracts.

  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 for the years ended December 31, 2000 and 1999,
respectively. 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. The fair value of fixed rate debt was based on quoted
market prices based on trades of subordinated debt. The fair value of the
Redeemable Preferred Stock was based on a valuation provided by an outside
source.

                                       54
<PAGE>

<TABLE>
<CAPTION>

                                                                   Expected Year of Maturity
                                     ------------------------------------------------------------------------------    Fair
                                       2001        2002        2003       2004       2005     Thereafter   Total      Value
                                     ---------  -----------  ---------  ---------  ---------  ----------  ---------  ---------
                                                                     (dollars in millions)
<S>                                   <C>        <C>          <C>        <C>        <C>        <C>         <C>         <C>
Liabilities:
  Short-term debt  - variable rate      $ 1.3      $   -      $   -      $    -      $   -      $     -    $  1.3      $  1.3
    Average interest rate                8.37%                                                                8.37%
  Long-term debt - variable rate            -        2.3        9.1       329.1 (1)    6.8            -      347.3      347.3
    Average interest rate                   -       8.38%      8.38%       9.13%      8.38%           -       9.09%
  Long-term debt - fixed rate             0.5        0.5        0.5         0.5          -        275.0      277.0      276.4
    Average interest rate                8.00%      8.00%      8.00%       8.00%         -       10.25%      10.23%
Redeemable Preferred Stock                  -          -          -           -          -         50.0    $  50.0     $ 93.2
</TABLE>

  (1) After the February 2001 amendments to PAA's bank credit agreements, the
expected year of maturity for $320.0 million of this amount is 2005.

  At December 31, 1999, the carrying value of all variable rate bank debt and
the Redeemable Preferred Stock of $506.1 million and $138.8 million,
respectively, approximated the fair value and liquidation value, respectively,
at that date. The carrying value and fair value of the fixed rate debt was
$280.5 million and $268.1 million, respectively, at that date.

  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 $240.0 million, for which we would pay approximately $0.9 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 $0.3 million gain and a $0.2 million loss, respectively. These
instruments are based on LIBOR margins and provide for (1) a floor of 5% and a
ceiling of 6.5% with an expiration date of February 2001 for $90.0 million
notional principal amount (2) a floor of 6% and a ceiling of 8% with an
expiration date of August 2002 for $125.0 million notional principal amount and
(3) a ceiling of 5.7% with an expiration date of July 2008 for $25.0 million
notional principal amount. The counterparty has the option to terminate the
$25.0 million swap in July 2003, and either party may terminate in July 2005.

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.

                                       55
<PAGE>

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

  Information regarding our directors will be included in the proxy statement
for the 2001 annual meeting of stockholders (the "Proxy Statement") to be filed
within 120 days after December 31, 2000, and is incorporated herein by
reference. Information with respect to our executive officers is presented in
Part I, Item 4 of this report.

ITEM 11.  EXECUTIVE COMPENSATION

  Information regarding executive compensation will be included in the Proxy
Statement and is incorporated herein by reference.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

  Information regarding beneficial ownership will be included in the Proxy
Statement and is incorporated herein by reference.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

  Information regarding certain relationships and related transactions will be
included in the Proxy Statement and is incorporated herein by reference.

                                       56
<PAGE>

                                    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

     2.1  Stock Purchase Agreement dated as of March 15, 1998, among Plains
          Resources Inc., Plains All American Inc. and Wingfoot Ventures Seven
          Inc. (incorporated by reference to Exhibit 2(b) to the Company's
          Annual Report on Form 10-K for the year ended December 31, 1997).

     3.1  Second Restated Certificate of Incorporation of the Company
          (incorporated by reference to Exhibit 3(a) to the Company's Annual
          Report on Form 10-K for the year ended December 31, 1995).

     3.2  Bylaws of the Company, as amended to date (incorporated by reference
          to Exhibit 3(b) to the Company's Annual Report on Form 10-K for the
          year ended December 31, 1993).

     3.3  Certificate of Designation, Preference and Rights of Series D
          Cumulative Convertible Preferred Stock (incorporated by reference to
          Exhibit 3(c) to the Company's Quarterly Report on Form 10-Q for the
          quarter ended September 30, 1997).

     3.4  Certificate of Designation, Preference and Rights of Series F
          Cumulative Convertible Preferred Stock (incorporated by reference to
          Exhibit 3(d) to the Company's Annual Report on Form 10-K for the year
          ended December 31, 1999).

     3.5  Certificate of Designation, Preference and Rights of Series G
          Cumulative Convertible Preferred Stock (incorporated by reference to
          Exhibit 3(e) to the Company's Annual Report on Form 10-K for the year
          ended December 31, 1999).

    *3.6  Certificate of Designation, Preference and Rights of Series H
          Cumulative Convertible Preferred Stock.

     4.1  Indenture dated as of March 15, 1996, among the Company, the
          Subsidiary Guarantors named therein and Texas Commerce Bank National
          Association, as Trustee for the Company's 10  1/4% Senior Subordinated
          Notes due 2006, Series A and Series B (incorporated by reference to
          Exhibit 4(b) to the Company's Form S-3 (Registration No. 333-1851)).

     4.2  Indenture dated as of July 21, 1997, among the Company, the
          Subsidiary Guarantors named therein and Texas Commerce Bank National
          Association, as Trustee for the Company's 10  1/4% Senior Subordinated
          Notes due 2006, Series C and Series D (incorporated by reference to
          Exhibit 4 to the Company's Quarterly Report on Form 10-Q for the
          quarterly period ended June 30, 1997).

     4.3  Specimen Common Stock Certificate (incorporated by reference to
          Exhibit 4 to the Company's Form S-1 Registration Statement (Reg. No.
          33-33986)).

     4.4  Purchase Agreement for Stock Warrant dated May 16, 1994, between
          Plains Resources Inc. and Legacy Resources, Co., L.P. (incorporated by
          reference to Exhibit 4(d) to the Company's Quarterly Report on Form
          10-Q for the quarterly period ended June 30, 1994).

     4.5  Warrant dated November 12, 1997, to Shell Land & Energy Company for
          the purchase of 150,000 shares of Common Stock (incorporated by
          reference to Exhibit 4(d) to the Company's Quarterly Report on Form
          10-Q for the quarterly period ended September 30, 1997).

     4.6  Indenture dated as of September 15, 1999, among Plains Resources Inc.,
          the Subsidiary Guarantors named therein and Chase Bank of Texas,
          National Association, as Trustee (incorporated by reference to Exhibit
          4(a) to the Company's Quarterly Report on Form 10-Q for the quarterly
          period ended September 30, 1999).

     4.7  Registration Rights Agreement dated as of September 22, 1999, among
          Plains Resources Inc., the Subsidiary Guarantors named therein, J.P.
          Morgan Securities Inc. and First Union Capital Markets Corp.
          (incorporated by reference to Exhibit 4(b) to the Company's Quarterly
          Report on Form 10-Q for the quarterly period ended September 30,
          1999).

     4.8  Stock Purchase Agreement dated as of December 15, 1999, among Plains
          Resources Inc. and the purchasers named therein (incorporated by
          reference to Exhibit 4(g) to the Company's Annual Report on Form 10-K
          for the year ended December 31, 1999).

     4.9  Amendment to Stock Purchase Agreement dated as of December 17, 1999,
          among Plains Resources Inc. and the purchasers named therein
          (incorporated by reference to Exhibit 4(h) to the Company's Annual
          Report on Form 10-K for the year ended December 31, 1999).

  **10.1  Employment Agreement dated as of March 1, 1993, between the Company
          and Greg L. Armstrong (incorporated by reference to Exhibit 10(b) to
          the Company's Annual Report on Form 10-K for the year ended December
          31, 1993).

  **10.2  The Company's 1991 Management Options (incorporated by reference to
          Exhibit 4.1 to the Company's Form S-8 Registration Statement (Reg. No.
          33-43788)).

                                       57
<PAGE>

  **10.3  The Company's 1992 Stock Incentive Plan (incorporated by reference to
          Exhibit 4.3 to the Company's Form S-8 Registration Statement (Reg. No.
          33-48610)).

  **10.4  The Company's Amended and Restated 401(k) Plan (incorporated by
          reference to Exhibit 10(d) to the Company's Annual Report on Form 10-K
          for the year ended December 31, 1996).

  **10.5  The Company's 1996 Stock Incentive Plan (incorporated by reference to
          Exhibit 4 to the Company's Form S-8 Registration Statement (Reg. No.
          333-06191)).

  **10.6  Stock Option Agreement dated August 27, 1996 between the Company and
          Greg L. Armstrong (incorporated by reference to Exhibit 10(l) to the
          Company's Annual Report on Form 10-K for the year ended December 31,
          1996).

  **10.7  Stock Option Agreement dated August 27, 1996 between the Company and
          William C. Egg Jr. (incorporated by reference to Exhibit 10(m) to the
          Company's Annual Report on Form 10-K for the year ended December 31,
          1996).

  **10.8  First Amendment to the Company's 1992 Stock Incentive Plan
          (incorporated by reference to Exhibit 10(n) to the Company's Annual
          Report on Form 10-K for the year ended December 31, 1996).

  **10.9  Second Amendment to the Company's 1992 Stock Incentive Plan
          (incorporated by reference to Exhibit 10(b) to the Company's Quarterly
          Report on Form 10-Q for the quarterly period ended June 30, 1997).

    10.10 Fourth Amended and Restated Credit Agreement dated May 22,1998,
          among the Company and ING (U.S.) Capital Corporation, et. al.
          (incorporated by reference to Exhibit 10(y) to the Company's Quarterly
          Report on Form 10-Q for the quarterly period ended June 30, 1998).

  **10.11 First Amendment to Plains Resources Inc. 1996 Stock Incentive Plan
          dated May 21, 1998 (incorporated by reference to Exhibit 10(z) to the
          Company's Quarterly Report on Form 10-Q for the quarterly period ended
          September 30, 1998)

  **10.12 Third Amendment to Plains Resources Inc. 1992 Stock Incentive Plan
          dated May 21, 1998 (incorporated by reference to Exhibit 10(aa) to the
          Company's Quarterly Report on Form 10-Q for the quarterly period ended
          September 30, 1998).

    10.13 First Amendment to Fourth Amended and Restated Credit Agreement
          dated as of November 17, 1998, among the Company and ING (U.S.)
          Capital Corporation, et. al. (incorporated by reference to Exhibit
          10(m) to the Company's Annual Report on Form 10-K for the year ended
          December 31, 1998).

    10.14 Second Amendment to Fourth Amended and Restated Credit Agreement
          dated as of March 15, 1999, among the Company and ING (U.S.) Capital
          Corporation, et. al.  (incorporated by reference to Exhibit 10(n) to
          the Company's Annual Report on Form 10-K for the year ended December
          31, 1998).

  **10.15 Employment Agreement dated as of November 23, 1998, between Harry N.
          Pefanis and the Company (incorporated by reference to Exhibit 10(o) to
          the Company's Annual Report on Form 10-K for the year ended December
          31, 1998).

    10.16 Purchase and Sale Agreement dated June 4, 1999, by and among the
          Company, Chevron U.S.A., Inc., and Chevron Pipe Line Company
          (incorporated by reference to Exhibit 10(h) to the Company's Quarterly
          Report on Form 10-Q for the quarterly period ended June 30, 1999).

    10.17 Third Amendment to Fourth Amended and Restated Credit Agreement
          dated June 21, 1999, among the Company and ING (U.S.) Capital
          Corporation, et. al. (incorporated by reference to Exhibit 10(p) to
          the Company's Quarterly Report on Form 10-Q for the quarterly period
          ended June 30, 1999).

    10.18 Second Amendment to Plains Resources 1996 Stock Incentive Plan dated
          May 20, 1999 (incorporated by reference to Exhibit 10(q) to the
          Company's Quarterly Report on Form 10-Q for the quarterly period ended
          June 30, 1999).

    10.19 Fourth Amendment to Fourth Amended and Restated Credit Agreement
          dated September 15, 1999, among the Company and First Union National
          Bank, et al. (incorporated by reference to Exhibit 10(q) to the
          Company's Quarterly Report on Form 10-Q for the quarterly period ended
          September 30, 1999).

    10.20 Fifth Amendment to Fourth Amended and Restated Credit Agreement dated
          December 1, 1999, among the Company and First Union National Bank, et
          al (incorporated by reference to Exhibit 10(t) to the Company's Annual
          Report on Form 10-K for the year ended December 31, 1999).

    10.21 Sixth Amendment to Fourth Amended and Restated Credit Agreement dated
          June 12, 2000, among the Company and First Union National Bank, et al
          (incorporated by reference to Exhibit 10.1 to the Company's Quarterly
          Report on Form 10-Q for the quarterly period ended June 30, 2000).

    10.22 Seventh Amendment to Fourth Amended and Restated Credit Agreement
          dated October 11, 2000, among the Company and First Union National
          Bank, et al (incorporated by reference to Exhibit 10.1 to the
          Company's Quarterly Report on Form 10-Q for the quarterly period ended
          September 30, 2000).

   *10.23 Third Amendment to Plains Resources 1996 Stock Incentive Plan dated
          June 7, 2000.

                                       58
<PAGE>

    10.24 Forms of Officer Stock Option Agreement (incorporated by reference
          to Exhibits 4.1 and 4.2 to the Company's Form S-8 Registration
          Statement (Reg No. 333-45562)

    10.25 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 for Plains All
          American, L.P.).

    10.26 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 for Plains All American
          Pipeline, L.P.).

    10.27 Plains All American Inc., 1998 Management Incentive Plan
          (incorporated by reference to Exhibit 10.05 to Annual Report on Form
          10-K for the Year Ended December 31, 1998 for Plains All American
          Pipeline, L.P.).

    10.28 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 for Plains All American Pipeline, L.P.).

    10.29 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 for Plains All American
          Pipeline, L.P.).

    10.30 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 for
          Plains All American Pipeline, L.P.).

    10.31 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 for Plains All American Pipeline, L.P.).

    10.32 Form of Transaction Grant Agreement (Payment on Vesting)
          (incorporated by reference to Exhibit 10.12 to Registration Statement,
          file No. 333-64107 for Plains All American Pipeline, L.P.).

    10.33 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 for Plains All American Pipeline, L.P.).

    10.34 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

    10.35 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 for Plains All American Pipeline, L.P.).

  **10.36 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 1999 for Plains All American Pipeline, L.P.).

    10.37 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 10.26 to Annual Report on Form 10-K for the Year
          Ended December 31, 1999 for Plains All American Pipeline, L.P.).

    10.38 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 Plains All American
          Pipeline, L.P. for the quarterly period ended March 31, 2000).

    10.39 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 Plains All American Pipeline, L.P. for the
          quarterly period ended March 31, 2000).

    10.40 First Amendment to Credit Agreement [Letter of Credit and Hedged
          Inventory Facility] dated as of February 26, 2001 (incorporated by
          reference to Exhibit 10.17 to Annual Report on Form 10-K for the Year
          Ended December 31, 2000 for Plains All American Pipeline, L.P.).

    10.41 First Amendment to Credit Agreement [Revolving Credit Facility] dated
          as of February 26, 2001 (incorporated by reference to Exhibit 10.187
          to Annual Report on Form 10-K for the Year Ended December 31, 2000 for
          Plains All American Pipeline, L.P.).

                                       59
<PAGE>

    21.1  Subsidiaries of the Company (incorporated by reference to Exhibit 21
          to the Company's Annual Report on Form 10-K for the year ended
          December 31, 1999) .

   *23.1  Consent of PricewaterhouseCoopers LLP.

   *23.2  Consent of H.J. Gruy and Associates, Inc.

   *23.3  Consent of Netherland, Sewell and Associates, Inc.

   *23.4  Consent of Ryder Scott Company.

--------------
 * Filed herewith
** A management contract or compensation plan.

(B)  REPORTS ON FORM 8-K

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

                                       60
<PAGE>

                                   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 RESOURCES INC.



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


Date:  April 2, 2001          By:  /s/ Jerry L. Dees
                                 ----------------------------------------------
                                    Jerry L. Dees, Director



Date:  April 2, 2001          By:  /s/ Tom H. Delimitros
                                 ----------------------------------------------
                                    Tom H. Delimitros, Director



Date:  April 2, 2001          By:  /s/ Cynthia A. Feeback
                                 ----------------------------------------------
                                    Cynthia A. Feeback, Vice President -
                                    Accounting And Assistant Treasurer
                                    (Principal Accounting Officer)



Date:  April 2, 2001          By:  /s/ William M. Hitchcock
                                 -----------------------------------------------
                                    William M. Hitchcock, Director



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



Date:  April 2, 2001          By:  /s/ Dan M. Krausse
                                 ---------------------------------------------
                                    Dan M. Krausse, Chairman of the Board and
                                    Director

                                       61
<PAGE>

Date:  April 2, 2001          By:  /s/ John H. Lollar
                                 ---------------------------------------------
                                    John H. Lollar, Director



Date:  April 2, 2001          By:  /s/ Robert V. Sinnott
                                 --------------------------------------------
                                    Robert V. Sinnott, Director



Date:  April 2, 2001          By:  /s/ J. Taft Symonds
                                 --------------------------------------------
                                    J. Taft Symonds, Director


  Our annual report to stockholders for the year ended December 31, 2000, and
the proxy statement relating to the annual meeting of stockholders will be
furnished to stockholders subsequent to the filing of this annual report on Form
10-K. Such documents have not been mailed to stockholders as of the date of this
report.

                                       62
<PAGE>

                             PLAINS RESOURCES INC.

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
                                                                                                    Page
                                                                                                    ----
<S>                                                                                                 <C>
Financial Statements
  Report of Independent Accountants..............................................................   F-2
  Consolidated Balance Sheets as of December 31, 2000 and 1999...................................   F-3
  Consolidated Statements of Operations for the years ended December 31, 2000, 1999 and 1998.....   F-4
  Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998.....   F-5
  Consolidated Statements of Changes in Non-redeemable Preferred Stock, Common Stock and Other
    Stockholders' Equity for the years ended December 31, 2000, 1999 and 1998....................   F-6
  Notes to Consolidated Financial Statements.....................................................   F-7
</TABLE>

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
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and
Stockholders of Plains Resources Inc.

In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Plains
Resources Inc. and its subsidiaries at December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company'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.

As discussed in Note 2 to the consolidated financial statements, the Company
changed its method of accounting for its crude oil inventories in connection
with its adoption of Staff Accounting Bulletin No. 101, "Revenue Recognition in
Financial Statements", effective January 1, 2000.

PricewaterhouseCoopers LLP

Houston, Texas
March 22, 2001

                                      F-2
<PAGE>

                    PLAINS RESOURCES INC. AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEETS
                       (IN THOUSANDS, EXCEPT SHARE DATA)

<TABLE>
<CAPTION>

                                                                               December 31,
                                                                        -------------------------
                                                                            2000          1999
                                                                        ----------     ----------
<S>                                                                     <C>            <C>
                                ASSETS

CURRENT ASSETS
Cash and cash equivalents                                               $    5,080     $   68,228
Accounts receivable and other                                              375,485        521,948
Inventory                                                                   54,844         40,478
Assets held for sale (Note 6)                                                    -        141,486
                                                                        ----------     ----------
Total current assets                                                       435,409        772,140
                                                                        ----------     ----------

PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method
  Subject to amortization                                                  762,245        671,928
  Not subject to amortization                                               42,581         52,031
Crude oil pipeline, gathering and terminal assets                          470,460        458,502
Other property and equipment                                                 6,453          7,706
                                                                        ----------     ----------
                                                                         1,281,739      1,190,167

Less allowance for depreciation, depletion and amortization               (437,465)      (402,514)
                                                                        ----------     ----------
                                                                           844,274        787,653
                                                                        ----------     ----------
OTHER ASSETS                                                               114,646        129,767
                                                                        ----------     ----------
                                                                        $1,394,329     $1,689,560
                                                                        ==========     ==========
                      LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable and other current liabilities                          $  413,309     $  546,393
Notes payable and other current obligations                                  1,811        109,880
                                                                        ----------     ----------
Total current liabilities                                                  415,120        656,273

BANK DEBT                                                                   27,300        137,300
BANK DEBT OF A SUBSIDIARY                                                  320,000        259,450
SUBORDINATED DEBT                                                          277,543        277,909
OTHER LONG-TERM DEBT                                                         1,533          2,044
OTHER LONG-TERM LIABILITIES AND DEFERRED CREDITS                             3,422         21,107
                                                                        ----------     ----------
                                                                         1,044,918      1,354,083
                                                                        ----------     ----------
COMMITMENTS AND CONTINGENCIES (NOTE 16)

MINORITY INTEREST                                                          162,271        156,045
                                                                        ----------     ----------
CUMULATIVE CONVERTIBLE PREFERRED STOCK,
  STATED AT LIQUIDATION PREFERENCE                                          50,000        138,813
                                                                        ----------     ----------
NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK
 AND OTHER STOCKHOLDERS' EQUITY

Series D Cumulative Convertible Preferred Stock, $1.00 par value,
  46,600 shares authorized, issued and outstanding, at stated value         23,300         23,300
Series H Cumulative Convertible Preferred Stock, $1.00 par value,
  175,000 shares authorized, 169,571 shares issued
  and outstanding, at stated value                                          84,785              -
Common Stock, $0.10 par value, 50,000,000 shares authorized;
  18,746,612 shares and 17,924,050 shares issued
  at December 31, 2000 and 1999, respectively                                1,875          1,792
Additional paid-in capital                                                 139,203        130,027
Accumulated deficit                                                        (88,410)      (114,500)
Treasury stock, at cost                                                    (23,613)             -
                                                                        ----------     ----------
                                                                           137,140         40,619
                                                                        ----------     ----------
                                                                        $1,394,329     $1,689,560
                                                                        ==========     ==========
</TABLE>

                See notes to consolidated financial statements.

                                      F-3
<PAGE>

                    PLAINS RESOURCES INC. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF OPERATIONS
                       (IN THOUSANDS, EXCEPT SHARE DATA)

<TABLE>
<CAPTION>
                                                                             Year Ended December 31,
                                                                   ----------------------------------------
                                                                      2000           1999          1998
                                                                   ----------    -----------    -----------
<S>                                                                <C>           <C>            <C>
REVENUES
Oil and natural gas sales                                          $  149,342    $   116,223    $  102,754
Marketing, transportation, storage and terminalling revenues        6,425,644     10,796,998     3,454,635
Gain on PAA unit offerings                                                  -          9,787        60,815
Gain on sale of assets (Note 6)                                        48,188         16,457             -
Interest and other income                                               7,411          1,237           834
                                                                   ----------    -----------    ----------
                                                                    6,630,585     10,940,702     3,619,038
                                                                   ----------    -----------    ----------
EXPENSES
Production expenses                                                    62,140         55,645        50,827
Marketing, transportation, storage and terminalling expenses        6,292,615     10,689,308     3,416,274
Unauthorized trading losses and related expenses (Note 3)               7,963        166,440         7,100
General and administrative                                             50,776         31,402        10,778
Depreciation, depletion and amortization                               47,221         36,998        31,020
Reduction in carrying cost of oil and natural gas properties                -              -       173,874
Interest expense                                                       55,828         46,378        35,730
                                                                   ----------    -----------    ----------
                                                                    6,516,543     11,026,171     3,725,603
                                                                   ----------    -----------    ----------
Income (loss) before income taxes, minority interest,
  extraordinary item and cumulative effect of accounting change       114,042        (85,469)     (106,565)
Minority interest                                                      42,535        (40,203)          786
                                                                   ----------    -----------    ----------
Income (loss) before income taxes, extraordinary item
  and cumulative effect of accounting change                           71,507        (45,266)     (107,351)
Income tax expense (benefit):
  Current                                                               1,020             (7)          862
  Deferred                                                             24,563        (20,472)      (45,867)
                                                                   ----------    -----------    ----------
Income (loss) before extraordinary item
  and cumulative effect of accounting change                           45,924        (24,787)      (62,346)
Extraordinary item, net of tax benefit
  and minority interest (Note 12)                                      (4,988)          (544)            -
Cumulative effect of accounting change,
  net of tax benefit (Note 2)                                            (121)             -             -
                                                                   ----------    -----------    ----------
NET INCOME (LOSS)                                                      40,815        (25,331)      (62,346)
Less:  cumulative preferred stock dividends                            14,725         10,026         4,762
                                                                   ----------    -----------    ----------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS                 $   26,090    $   (35,357)   $  (67,108)
                                                                   ==========    ===========    ==========
Basic earnings per share:
  Income (loss) before extraordinary item and
   cumulative effect of accounting change                          $     1.75    $     (2.02)   $    (3.99)
  Extraordinary item                                                    (0.28)         (0.03)            -
  Cumulative effect of accounting change                                (0.01)             -             -
                                                                   ----------    -----------    ----------
  Net income (loss)                                                $     1.46    $     (2.05)   $    (3.99)
                                                                   ==========    ===========    ==========
Diluted earnings per share:
  Income (loss) before extraordinary item and
   cumulative effect of accounting change                          $     1.56    $     (2.02)   $    (3.99)
  Extraordinary item                                                    (0.17)         (0.03)            -
  Cumulative effect of accounting change                                    -              -             -
                                                                   ----------    -----------    ----------
  Net income (loss)                                                $     1.39    $     (2.05)   $    (3.99)
                                                                   ==========    ===========    ==========
</TABLE>

                See notes to consolidated financial statements.

                                      F-4
<PAGE>

                    PLAINS RESOURCES INC. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                            Year Ended December 31,
                                                                   --------------------------------------
                                                                       2000          1999         1998
                                                                   -----------    ---------    ----------
<S>                                                                <C>            <C>          <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)                                                  $    40,815    $ (25,331)   $ (62,346)
Items not affecting cash flows from operating activities:
  Depreciation, depletion and amortization                              47,221       36,998       31,020
  Reduction in carrying costs of oil and natural gas properties              -            -      173,874
  Noncash gains (Notes 4 and 6)                                        (48,188)     (26,244)     (70,037)
  Minority interest in income of a subsidiary                           35,566      (40,203)         786
  Deferred income taxes                                                 21,297      (20,472)     (45,867)
  Noncash compensation expense                                           2,682        1,013            -
  Allowance for doubtful accounts                                        5,000            -            -
  Other noncash items                                                   10,925          (61)          90
Change in assets and liabilities from operating activities:
  Accounts receivable and other                                        102,651     (226,438)      24,084
  Inventory                                                            (13,977)      33,930      (19,057)
  Pipeline linefill                                                    (16,679)          (3)      (3,904)
  Accounts payable and other current liabilities                      (143,453)     171,974        8,987
  Other long-term liabilities                                           (8,000)      18,873            -
                                                                   -----------    ---------    ---------
Net cash provided by (used in) operating activities                     35,860      (75,964)      37,630
                                                                   -----------    ---------    ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for midstream acquisitions (Note 6)                                 -     (176,918)    (394,026)
Payment for crude oil pipeline, gathering and terminal assets          (12,219)     (12,507)      (8,131)
Proceeds from the sale of oil and natural gas properties                     -            -          131
Payment for acquisition, exploration and developments costs            (78,726)     (77,899)     (80,318)
Payment for additions to other property and assets                      (3,133)      (2,472)      (1,078)
Proceeds from asset sales (Note 6)                                     224,261        3,400            -
                                                                   -----------    ---------    ---------
Net cash provided by (used in) investing activities                    130,183     (266,396)    (483,422)
                                                                   -----------    ---------    ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt                                         1,698,575      744,971      570,560
Proceeds from short-term debt                                           51,300      131,119       31,750
Proceeds from sale of capital stock, options and warrants                2,301        5,542          828
Proceeds from issuance of preferred stock                                    -       50,000       85,000
Proceeds from issuance of common units, net (Note 4)                         -       50,759      241,690
Principal payments of long-term debt                                (1,799,186)    (449,332)    (423,560)
Principal payments of short-term debt                                 (108,719)     (82,150)     (40,000)
Purchase of treasury stock                                             (23,613)           -            -
Costs incurred in connection with financing arrangements                (6,748)     (19,448)     (13,075)
Preferred stock dividends                                              (13,409)      (4,245)           -
Distributions to unitholders                                           (29,432)     (22,201)           -
Other                                                                     (260)        (971)      (4,571)
                                                                   -----------    ---------    ---------
Net cash provided by (used in) financing activities                   (229,191)     404,044      448,622
                                                                   -----------    ---------    ---------
Net increase (decrease) in cash and cash equivalents                   (63,148)      61,684        2,830
Cash and cash equivalents, beginning of year                            68,228        6,544        3,714
                                                                   -----------    ---------    ---------
Cash and cash equivalents, end of year                             $     5,080    $  68,228    $   6,544
                                                                   ===========    =========    =========
</TABLE>

                See notes to consolidated financial statements.

                                      F-5
<PAGE>

                    PLAINS RESOURCES INC. AND SUBSIDIARIES
             CONSOLIDATED STATEMENTS OF CHANGES IN NON-REDEEMABLE
         PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
                                (IN THOUSANDS)

<TABLE>
<CAPTION>

                                                                2000                        1999                    1998
                                                     -------------------------  ------------------------   ----------------------
                                                          SHARES      AMOUNT       SHARES       AMOUNT        SHARES      AMOUNT
                                                     -----------    ----------  -----------    ---------   -----------  ----------
<S>                                                  <C>          <C>           <C>           <C>          <C>          <C>
SERIES D CUMULATIVE CONVERTIBLE PREFERRED STOCK
  Balance, beginning of year                                 47     $  23,300            47    $  21,946           47     $ 20,671
  Preferred stock dividends                                   -             -             -        1,354            -        1,275
                                                         ------     ---------        ------    ---------       ------     --------
  Balance, end of year                                       47     $  23,300            47    $  23,300           47     $ 21,946
                                                         ------     ---------        ------    ---------       ------     --------
SERIES H CUMULATIVE CONVERTIBLE PREFERRED STOCK
  Balance, beginning of year                                  -     $       -             -    $       -            -     $      -
  Shares issued upon conversion of
    redeemable preferred stock                              170        84,785             -            -            -            -
                                                         ------     ---------        ------    ---------       ------     --------
  Balance, end of year                                      170     $  84,785             -    $       -            -     $      -
                                                         ------     ---------        ------    ---------       ------     --------
COMMON STOCK
  Balance, beginning of year                             17,924     $   1,792        16,882    $   1,688       16,703     $  1,670
  Capital stock issued upon exercise
    of options, warrants and other                          557            56           943           94          179           18
  Conversion of preferred
    stock into common                                       266            27            99           10            -            -
                                                         ------     ---------        ------    ---------       ------     --------
  Balance, end of year                                   18,747     $   1,875        17,924    $   1,792       16,882     $  1,688
                                                         ------     ---------        ------    ---------       ------     --------
ADDITIONAL PAID-IN CAPITAL
  Balance, beginning of year                                        $ 130,027                  $ 124,679                  $122,887
  Capital stock issued upon exercise
    of options, warrants and other                                      5,223                      3,583                     1,792
  Conversion of preferred
    stock into common                                                   3,958                      1,765                        -
  Redemption of preferred stock                                            (5)                         -                        -
                                                                    ---------                  ---------                  --------
  Balance, end of year                                              $ 139,203                  $ 130,027                  $124,679
                                                                    ---------                  ---------                  --------
ACCUMULATED DEFICIT
  Balance, beginning of year                                        $(114,500)                 $ (79,143)                 $(12,035)
  Preferred stock dividends                                           (14,725)                   (10,026)                   (4,762)
  Net income (loss)                                                    40,815                    (25,331)                  (62,346)
                                                                    ---------                  ---------                  --------
  Balance, end of year                                              $ (88,410)                 $(114,500)                 $(79,143)
                                                                    ---------                  ---------                  --------
TREASURY STOCK
  Balance, beginning of year                                  -     $       -             -    $       -            -     $      -
  Purchase of treasury stock                             (1,291)      (23,613)            -            -            -            -
                                                         ------     ---------        ------    ---------       ------     --------
  Balance, end of year                                   (1,291)    $ (23,613)            -    $                    -     $
                                                         ------     ---------        ------    ---------       ------     --------
TOTAL                                                               $ 137,140                  $  40,619                  $ 69,170
                                                                    =========                  =========                  ========
</TABLE>

                See notes to consolidated financial statements.


                                      F-6
<PAGE>

                             PLAINS RESOURCES INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 -- Organization and Basis of Presentation

 Organization

  We are an independent energy company that is engaged in two related lines of
business. Our first line of business, which we refer to as "upstream", acquires,
exploits, develops, explores and produces crude oil and natural gas. Our second
line of business, which we refer to as "midstream", is engaged in the 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". We conduct
this second line of business through our majority ownership in Plains All
American Pipeline, L.P. ("PAA"). Our upstream crude oil and natural gas
activities are focused in California (in the Los Angeles Basin, the Arroyo
Grande Field, and the Mt. Poso Field), California Outer Continental Shelf
("OCS") (in the Point Arguello Field), the Sunniland Trend of South Florida and
the Illinois Basin in southern Illinois. Our midstream activities are
concentrated in California, Texas, Oklahoma, Louisiana, Illinois and the Gulf of
Mexico.

 Basis of Consolidation and Presentation

  The consolidated financial statements include the accounts of Plains Resources
Inc., our wholly owned subsidiaries and PAA, in which we have an approximate 54%
ownership interest. Plains All American Inc., one of our wholly owned
subsidiaries, serves as PAA's sole general partner. For financial statement
purposes, the assets, liabilities and earnings of PAA are included in our
consolidated financial statements, with the public unitholders' interest
reflected as a minority interest. All significant intercompany transactions have
been eliminated. Certain reclassifications have been made to the prior year
statements to conform to the current year 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 include (1) crude oil
and natural gas reserves, (2) depreciation, depletion and amortization,
including future abandonment costs, (3) income taxes and related valuation
allowance, (4) allowance for doubtful accounts receivable and (5) accrued
liabilities. Although management believes these estimates are reasonable, actual
results could differ from these estimates.

  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 two institutions and at times
may exceed federally insured limits. We periodically assess the financial
condition of the institutions 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. Crude oil inventories related to oil and gas producing operations
are carried at cost. Crude oil inventories related to marketing, transportation,
storage and terminalling operations are carried at the lower of cost, as
adjusted for deferred hedging gains and losses, or market value using an average
cost method. Materials and supplies inventory is stated at the lower of cost or
market with cost determined on an average cost method.

  Inventory consists of the following (in thousands):

<TABLE>
<CAPTION>
                                  December 31,
                             --------------------
                                2000       1999
                            ---------   ---------
<S>                          <C>        <C>
Crude oil                     $49,261    $35,664
Materials and supplies          5,583      4,814
                              -------    -------
                              $54,844    $40,478
                              =======    =======

</TABLE>

                                      F-7
<PAGE>

  Oil and Natural Gas Properties. We follow the full cost method of accounting
whereby all costs associated with property acquisition, exploration,
exploitation and development activities are capitalized. Such costs include
internal general and administrative costs such as payroll and related benefits
and costs directly attributable to employees engaged in acquisition,
exploration, exploitation and development activities. General and administrative
costs associated with production, operations, marketing and general corporate
activities are expensed as incurred. These capitalized costs along with our
estimate of future development and abandonment costs, net of salvage values and
other considerations, are amortized to expense by the unit-of-production method
using engineers' estimates of unrecovered proved oil and natural gas reserves.
The costs of unproved properties are excluded from amortization until the
properties are evaluated. Interest is capitalized on oil and natural gas
properties not subject to amortization and in the process of development.
Proceeds from the sale of oil and natural gas properties are accounted for as
reductions to capitalized costs unless such sales involve a significant change
in the relationship between costs and the estimated value of proved reserves, in
which case a gain or loss is recognized. Unamortized costs of proved properties
are subject to a ceiling which limits such costs to the present value of
estimated future cash flows from proved oil and natural gas reserves of such
properties reduced by future operating expenses, development expenditures and
abandonment costs (net of salvage values), and estimated future income taxes
thereon (the "Standardized Measure") (see Note 20).

  Crude Oil Pipeline, Gathering and Terminal Assets. Crude oil pipeline,
gathering and terminal assets are recorded at cost. 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; and

  .  trucking equipment, injection stations and other - 5 to 10 years.

Acquisitions and improvements are capitalized; maintenance and repairs are
expensed as incurred.

  Other Property and Equipment. Other property and equipment is recorded at cost
and consists primarily of office furniture and fixtures and computer hardware
and software. Acquisitions, renewals, and betterments are capitalized;
maintenance and repairs are expensed. Depreciation is provided using the
straight-line method over estimated useful lives of three to seven years. 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.

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

<TABLE>
<CAPTION>
                                                December 31,
                                            ---------------------
                                              2000         1999
                                            --------     --------
<S>                                        <C>          <C>
Pipeline linefill                           $ 34,312     $ 17,633
Deferred tax asset, net (see Note 11)         47,974       67,366
Debt issue costs (see Note 7)                 15,868       35,101
Land                                           8,853        8,853
Long-term receivable, net                      5,000            -
Other                                          7,176       10,965
                                            --------     --------
                                             119,183      139,918
Accumulated amortization                      (4,537)     (10,151)
                                            --------     --------
                                            $114,646     $129,767
                                            ========     ========
</TABLE>

  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.

  Pipeline Linefill. 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 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 we sold are included in investing activities in the
accompanying consolidated statements of cash flows (see Note 6).

                                      F-8
<PAGE>

  Federal and State Income Taxes. Income taxes are accounted for in accordance
with Statement of Financial Accounting Standards No. 109, Accounting for Income
Taxes ("SFAS 109"). SFAS 109 requires recognition of deferred tax liabilities
and assets for the expected future tax consequences of events that have been
included in the financial statements or tax returns. Under this method, deferred
tax liabilities and assets are determined based on the difference between the
financial statement and tax bases of assets and liabilities using tax rates in
effect for the year in which the differences are expected to reverse.

  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.

  Oil and gas revenue from our interests in producing wells is recognized when
the production volumes are sold. Transportation costs incurred in connection
with such operations, which are immaterial, are reflected as a reduction of
sales revenues.

  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 until the underlying hedged
transaction occurs. The financial impacts of crude oil hedge contracts are
included in our 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 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 long-term debt being hedged, resulting in an adjustment to the
effective interest rate.

  Stock 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 stock options. Under APB 25, no
compensation expense is recognized when the exercise price of options equals the
fair value (market price) of the underlying stock on the date of grant.

  Sale of Units by a Subsidiary. When a subsidiary sells additional units to a
third party, resulting in a change in our percentage ownership interest, we
recognize a gain or loss in our consolidated statement of operations if the
selling price per unit is more or less than our average carrying amount per
unit. When we buy additional units from a subsidiary, resulting in a change in
our percentage ownership interest, the difference between our cost and
underlying equity in investee net assets is assigned first to identifiable
tangible and intangible assets and to liabilities based on their fair values at
the date of the change of interest; any unassigned difference is assigned to
goodwill.

                                      F-9
<PAGE>

  Recent Accounting Pronouncements. In the fourth quarter of 2000, we adopted
Securities and Exchange Commission ("SEC") Staff Accounting Bulletin 101,
"Revenue Recognition in Financial Statements" ("SAB 101"). As a result, we
record revenue from crude oil production in the period it is sold as opposed to
when it is produced and carry any unsold production as inventory valued at
historical cost. The total effect of implementing SAB 101 was to reduce reported
sales volumes by 144,000 barrels for 2000 and net income for the year by
$175,000, including a $121,000 reduction for the cumulative effect of prior
years. The effect of this change in accounting for crude oil inventories on
prior periods was deminimus.

  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 in marketing,
transportation, storage and terminalling revenues and expenses in our statements
of operations for all periods presented, with no effect on earnings. The amounts
by which revenues and expenses have been reclassified for the years ended
December 31, 2000 and 1999 and 1998 are $2.5 billion, $6.2 billion and 2.3
billion, respectively.

  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. 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 net-of-tax and minority interest cumulative effect gain of $4.5
million in other comprehensive income and a net-of-tax and minority interest
cumulative effect charge of $2.0 million to earnings to recognize at fair value
all derivative instruments that were designated as cash flow hedging
instruments. Correspondingly, assets have been increased by $14.2 million and
liabilities and minority interest have been increased by $11.7 million.
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 equity through comprehensive income.

NOTE 3 -- UNAUTHORIZED TRADING LOSSES

  In November 1999, we discovered that a former employee of PAA 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 were recognized in
1998 and the remainder in 1999. In 2000, we recognized an additional $8.0
million charge for litigation related to the unauthorized trading losses (see
Note 17).

NOTE 4 -- PLAINS ALL AMERICAN PIPELINE, L.P. - FORMATION AND OFFERINGS

  Our midstream activities are conducted through PAA. PAA was formed in
September of 1998 to acquire and operate the business and assets of our wholly
owned midstream subsidiaries.

  On November 23, 1998, PAA completed an initial public offering of 13,085,000
common units at $20.00 per unit, representing limited partner interests and
received proceeds of approximately $244.7 million. Concurrently with the closing
of the initial public offering, certain of our midstream subsidiaries were
merged into Plains Resources Inc., and then we sold the assets of these
subsidiaries to PAA in exchange for $64.1 million and the assumption of $11.0
million of related

                                      F-10
<PAGE>

indebtedness. At the same time, the general partner conveyed all of its interest
in the All American Pipeline and the SJV Gathering System to PAA 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

  .  PAA's assumption of $175.0 million of indebtedness incurred by the general
     partner in connection with the acquisition of the All American Pipeline and
     the SJV Gathering System.

  In addition to the $64.1 million paid to us, PAA distributed approximately
$177.6 million to the general partner and used approximately $3.0 million of the
remaining proceeds to pay expenses incurred in connection with the offering. The
general partner used $121.0 million of the cash distributed to it to retire the
remaining indebtedness incurred in connection with the acquisition of the All
American Pipeline and the SJV Gathering System and to pay other costs associated
with the transactions. The general partner distributed the remaining $56.6
million to us, which we used to repay indebtedness and for other general
corporate purposes.

  During 1998, we recognized a pre-tax gain of approximately $60.8 million
($37.1 million after-tax) in connection with the formation of PAA. The gain was
net of approximately $9.2 million of formation related expenses consisting
primarily of amounts due to certain key employees in connection with the
successful formation of PAA, debt prepayment penalties and legal fees. The gain
is the result of an increase in the book value of our equity in PAA to reflect
our proportionate share of the underlying net assets of PAA due to the sale of
units in the initial public offering.

  In May 1999, PAA sold to the general partner 1.3 million Class B common units
of PAA for a total cash consideration of $25.0 million, or $19.25 per unit, the
price equal to the market value of PAA's common units on May 12, 1999, in
connection with the Scurlock acquisition (see Note 6).

  In October 1999, PAA completed a public offering of an additional 2,990,000
common units representing limited partner interests, at $18.00 per unit. Net
proceeds to PAA from the offering, including our general partner contribution of
$0.5 million, 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. We recognized a pre-tax
gain of $9.8 million ($6.0 million after-tax) in connection with the offering as
a result of an increase in the book value of our equity in PAA, as discussed
above. We held approximate interests of 59% and 54% before and after PAA's
secondary offering, respectively.

NOTE 5 -- UPSTREAM ACQUISITIONS

  On July 1, 1999, Arguello Inc., our wholly owned subsidiary, acquired
Chevron's interests in Point Arguello for approximately $1.0 million. The
interests acquired include Chevron's 26% working interest in the Point Arguello
Unit, its 26% interest in various partnerships owning the associated
transportation, processing and marketing infrastructure, and Chevron's right to
participate in surrounding leases and certain fee acreage onshore. We assumed
its 26% share of (1) plugging and abandoning all existing well bores, (2)
removing conductors, (3) flushing hydrocarbons from all lines and vessels and
(4) removing/abandoning all structures, fixtures and conditions created
subsequent to closing. Chevron retained the obligation for all other abandonment
costs, including but not limited to (1) removing, dismantling and disposing of
the existing offshore platforms,  (2) removing and disposing of all existing
pipelines and (3) removing, dismantling, disposing and remediation of all
existing onshore facilities.

  During 1998, we acquired the Mt. Poso field from Aera Energy LLC for
approximately $7.7 million. The field is located approximately 27 miles north of
Bakersfield, California, in Kern County. The field added approximately 8 million
barrels of oil equivalent to our proved reserves at the acquisition date.

NOTE 6 -- MIDSTREAM ACQUISITIONS AND DISPOSITIONS

 Scurlock Acquisition

  On May 12, 1999, PAA 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.

                                      F-11
<PAGE>

  Financing for the Scurlock acquisition was provided through:

  .  borrowings of approximately $92.0 million under a previous bank facility;

  .  the sale to the general partner of 1.3 million Class B common units of PAA
     for a total cash consideration of $25.0 million, or $19.125 per unit, the
     price equal to the market value of PAA's common units on May 12, 1999; and

  .  a $25.0 million draw under PAA's existing revolving credit agreement.

  The funds for the purchase of the Class B units by the general partner were
provided by a capital contribution from us. We financed our capital contribution
through our revolving credit facility.

  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):

<TABLE>
<CAPTION>

<S>                                                      <C>
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
                                                          ========
</TABLE>

 Pro Forma Results for the Scurlock Acquisition

  The following unaudited pro forma data is presented to show pro forma
revenues, net loss and basic and diluted net loss per share as if the Scurlock
acquisition, which was effective May 1, 1999, had occurred on January 1, of each
year presented (in thousands, except per share data):


<TABLE>
<CAPTION>
                                                            Year Ended December 31,
                                                           --------------------------
                                                              1999           1998
                                                           -----------    -----------
<S>                                                       <C>             <C>
Revenues                                                   $11,323,577     $4,854,504
                                                           ===========     ==========
Net loss                                                   $   (27,147)    $  (69,682)
                                                           ===========     ==========
Net loss per share available to common stockholders:
  Basic and diluted                                        $     (2.15)    $    (4.43)
                                                           ===========     ==========
</TABLE>

West Texas Gathering System Acquisition

  On July 15, 1999, PAA 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 the term loan portion of a previous credit
facility of PAA.

 All American Pipeline Acquisition

  On July 30, 1998, Plains All American Inc., 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 with the assets, liabilities and results of operations
included in our consolidated financial statements effective July 30, 1998.

                                      F-12
<PAGE>

  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):

<TABLE>
<S>                                                    <C>
Crude oil pipeline, gatheirng and terminal assets       $392,393
Other assets (debt issue costs)                            6,138
Net working capital items (excluding cash received
 of $7,481)                                                1,498
                                                        --------
Cash paid                                               $400,164
                                                        ========

</TABLE>

  Financing for the acquisition was provided through a $325.0 million, limited
recourse bank facility and an approximate $114.0 million capital contribution by
us. Actual borrowings at closing were $300.0 million.

Pro Forma Results for the All American Pipeline Acquisition

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


<TABLE>
<CAPTION>
                                      Year Ended
                                      December 31,
                                          1998
                                      ------------
<S>                                   <C>
Revenues                               $4,056,692
                                       ==========
Net loss                               $  (54,902)
                                       ==========
Basic and diluted net loss per share   $    (3.82)
                                       ==========
</TABLE>

 All American Pipeline Linefill Sale and Asset Disposition

  In March 2000, we sold to a unit of El Paso Corporation 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
costs and estimated costs to remove some equipment. We used the proceeds from
the sale to reduce the outstanding debt of PAA. 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 7 -- Long-Term Debt and Credit Facilities

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

<TABLE>
<CAPTION>
                                                                                December 31,
                                                                            ------------------
                                                                              2000      1999
                                                                            --------  --------
<S>                                                                         <C>       <C>
PAA letter of credit facility and hedged inventory facility, bearing
  interest at a weighted average interest rate 8.4% at December 31, 2000    $1,300     $      -
PAA letter of credit and borrowing facility, bearing interest at
  weighted average interest rate 8.7% at December 31, 1999                       -       13,719
PAA 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                                               511      51,161
                                                                             ------    --------
                                                                             $1,811    $109,880
                                                                             ======    ========
</TABLE>


                                      F-13
<PAGE>

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

<TABLE>
<CAPTION>
                                                                    December 31,
                                                                ---------------------
                                                                  2000        1999
                                                                -------      -------
<S>                                                             <C>          <C>
Revolving credit facility, bearing interest at 8.4%
  and 7.6%, at December 31, 2000 and 1999, respectively         $ 27,300     $137,300
Plains Marketing, L.P. revolving credit facility,
  bearing interest at 9.2%, at December 31, 2000                 320,000            -
PAA bank credit agreement, bearing interest at 8.3%
  at December 31, 1999                                                 -      225,000
Plains Scurlock bank credit agreement, bearing interest
  at 9.1% at December 31, 1999                                         -       85,100
10.25% Senior Subordinated Notes, due 2006, net of
  unamortized premium of $2.5 million and $2.9 million
  at December 31, 2000 and 1999, respectively                    277,543      277,909
Other long-term debt                                               2,044        2,555
                                                                --------     --------
  Total long-term debt                                           626,887      727,864
  Less current maturities                                           (511)     (51,161)
                                                                --------     --------
                                                                $626,376     $676,703
                                                                ========     ========
</TABLE>

 PLAINS RESOURCES LONG-TERM DEBT AND CREDIT FACILITIES

  Revolving Credit Facility

  We have a $225.0 million revolving credit facility with a group of banks. The
revolving credit facility is guaranteed by all of our upstream subsidiaries and
is collateralized by our upstream oil and natural gas properties and those of
the guaranteeing subsidiaries and the stock of all the upstream subsidiaries.
The borrowing base under the revolving credit facility at December 31, 2000, is
$225.0 million and is subject to redetermination from time to time by the
lenders in good faith, in the exercise of the lenders' sole discretion, and in
accordance with customary practices and standards in effect from time to time
for crude oil and natural gas loans to borrowers similar to our company. Our
borrowing base may be affected from time to time by the performance of our oil
and natural gas properties and changes in oil and natural gas prices. We incur a
commitment fee of 3/8% per annum on the unused portion of the borrowing base. In
addition, we pay a fee of 1 3/8% per annum of the face amount of letters of
credit that are issued under our revolving credit facility. The revolving credit
facility, as amended, terminates on July 1, 2002, at which time the remaining
outstanding balance converts to a term loan which is repayable in twelve equal
quarterly installments commencing October 1, 2002, with a final maturity of July
1, 2005. The revolving credit facility bears interest, at our option, of either
LIBOR plus 1 3/8% or Base Rate (as defined therein). At December 31, 2000,
letters of credit of $0.6 million were outstanding under the revolving credit
facility.

  The revolving credit facility contains covenants which, among other things,
prohibit the payment of cash dividends on common stock, limit repurchases of
common stock, limit the amount of consolidated debt, limit our ability to make
certain loans and investments and provide that we must maintain a specified
relationship between current assets and current liabilities. We are currently in
compliance with the covenants contained in the revolving credit facility. At
December 31, 2000, we could have borrowed the full $225.0 million available
under the revolving credit facility.

  10.25% Senior Subordinated Notes Due 2006

  We have $275.0 million principal amount of 10.25% Senior Subordinated Notes
Due 2006 outstanding, bearing a coupon rate of 10.25%, which at December 31,
2000 consists of (in thousands):

<TABLE>
<CAPTION>

<S>           <C>
Series A      $    500
Series B       149,500
Series C            50
Series D        49,950
Series E        75,000
              --------
              $275,000
              ========
</TABLE>

                                      F-14
<PAGE>

  The Series A and Series B 10.25% Notes were issued in 1996 at 99.38% of par to
yield 10.35%. The Series C and Series D 10.25% Notes were issued in 1997 at
approximately 107% of par. The Series E 10.25% Notes were issued in September
1999 pursuant to a Rule 144A private placement at approximately 101% of par.
Proceeds from the sale of the Series E 10.25% Notes, net of offering costs, were
approximately $74.6 million and were used to reduce the balance on our revolving
credit facility.

  The 10.25% Notes are redeemable, at our option, on or after March 15, 2001 at
105.13% of the principal amount thereof, at decreasing prices thereafter prior
to March 15, 2004, and thereafter at 100% of the principal amount thereof plus,
in each case, accrued interest to the date of redemption.

  The Indenture contains covenants that include, but are not limited to,
covenants that: (1) limit the incurrence of additional indebtedness; (2) limit
certain investments; (3) limit restricted payments; (4) limit the disposition of
assets; (5) limit the payment of dividends and other payment restrictions
affecting subsidiaries; (6) limit transactions with affiliates; (7) limit the
creation of liens; and (8) restrict mergers, consolidations and transfers of
assets. In the event of a Change of Control and a corresponding Rating Decline,
as both are defined in the Indenture, we will be required to make an offer to
repurchase the 10.25% Notes at 101% of the principal amount thereof, plus
accrued and unpaid interest to the date of the repurchase.

  The Series A-E Notes are unsecured general obligations and are subordinated in
right of payment to all our existing and future senior indebtedness and are
guaranteed by all of our upstream subsidiaries on a full, unconditional, joint
and several basis. The Series A-E Notes are not guaranteed by PAA or any of our
other midstream subsidiaries (see Note 24).

  On March 13, 2001, we exchanged the $75.0 million principal amount of Series E
Notes for 10.25% Senior Subordinated Notes due 2006, Series F. The Series F
Notes are substantially identical (including principal amount, interest rate,
maturity and redemption rights) to the Series E Notes for which they were
exchanged, except for certain transfer restrictions relating to the Series E
Notes.

 PLAINS ALL AMERICAN PIPELINE L.P. CREDIT FACILITIES

  The discussion below relates to credit facilities of PAA, which are
nonrecourse to us, but are included in our consolidated financial statements. In
addition, our indirect ownership in PAA does not collateralize any of our credit
facilities.

  At December 31, 2000, PAA's bank credit agreements consist of:

  .  a $400.0 million senior secured revolving credit facility. The revolving
     credit facility is secured by substantially all of PAA's assets and matures
     in April 2004. No principal is scheduled for payment prior to maturity. The
     revolving credit facility bears interest at PAA's option at either the base
     rate, as defined, plus an applicable margin, or LIBOR plus an applicable
     margin. PAA incurs 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 PAA's 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 PAA's 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.

  PAA's 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 PAA's 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.

                                      F-15
<PAGE>

  PAA's bank credit agreements treat a change of control as an event of default
and also require PAA 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 PAA's 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 PAA is in compliance with its bank
credit agreements, they do not restrict its ability to make distributions of
"available cash" as defined in their partnership agreement. PAA is currently in
compliance with the covenants contained in its credit agreements. At December
31, 2000, PAA could have borrowed the up to $386.4 million under its secured
revolving credit facility.

  In February 2001, PAA's 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 PAA to borrow an
additional $130.0 million under the terms of the senior secured revolving credit
facility. PAA has an underwritten commitment, subject to conditions, for the
$130.0 million.

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

  On December 30, 1999, PAA 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.

  At December 31, 1999 PAA 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. At
December 31, 1999, PAA 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 PAA's senior secured revolving credit facility.

 Maturities

  The aggregate amount of maturities of all long-term indebtedness for the next
five years is: 2001 - $0.5 million, 2002 - $2.8 million, 2003 - $9.6 million,
2004 - $329.6 million and 2005 - $6.8 million. After the February 2001
amendments to PAA's credit agreements, the maturities were: 2001 - $0.5 million,
2002 - $2.8 million, 2003 - $9.6 million, 2004 - $9.6 million and 2005 - $326.8
million.

NOTE 8 - REDEEMABLE PREFERRED STOCK

 Liquidation Preference

  All series of our cumulative convertible preferred stock are stated at
liquidation preference on the consolidated balance sheet. Liquidation preference
represents the number of shares outstanding, which includes cumulative noncash
dividends, multiplied by the stated value of the shares. Any unpaid cash
dividends are accrued in accounts payable and other current liabilities on the
consolidated balance sheet. We have no current intention of redeeming the
cumulative preferred stock before its mandatory redemption date. However, we
review our capital structure regularly and may redeem shares of our preferred
stock if future conditions warrant.

                                      F-16
<PAGE>

 Series E and Series G Cumulative Convertible Preferred Stock

  In connection with the sale of the Series F Preferred Stock described below,
we agreed with the purchasers of our Series F Preferred Stock (who were also
holders of the Series E Preferred Stock), to reduce the conversion price of the
Series E Preferred Stock from $18.00 to $15.00. This reduction of the conversion
price of the Series E Preferred Stock was effected through an exchange of each
outstanding share of Series E Preferred Stock for a share of a new Series G
Preferred Stock on February 1, 2000. Other than the reduction of the conversion
price, the terms of the Series G Preferred Stock were substantially identical to
those of the Series E Preferred Stock.

  In December 2000, we exchanged or redeemed all of the shares of Series G
Preferred Stock that had not been previously converted into shares of common
stock. We exchanged 169,571 shares of Series G Preferred Stock for 169,571
shares of our Series H Preferred Stock (see Note 9) and in connection therewith
paid $2.0 million, the amount equal to accrued dividends, and converted 1,825
shares of Series G Preferred Stock into 62,226 shares of common stock. The
remaining 213 shares of the Series G Preferred Stock were redeemed at 105% of
stated value in accordance with the original terms. In connection with that
redemption, we paid $114,000 consisting of $112,000 for stated value and $2,000
for accrued and unpaid dividends. In 2000, we paid cash dividends of
approximately $8.4 million on the Series G Preferred Stock for the period from
October 1, 1999 through September 30, 2000.

  The Series E Cumulative Convertible Preferred Stock (the "Series E Preferred
Stock") was sold in a private placement on July 29, 1998 for $85.0 million. Each
share of the Series E Preferred Stock had a stated value of $500 per share and
bore a dividend of 9.5% per annum. Dividends were payable semi-annually in
either cash or additional shares of Series E Preferred Stock at our option and
were cumulative from the date of issue. Each share of Series E Preferred Stock
was convertible into 27.78 shares of common stock (an initial effective
conversion price of $18.00 per share) and in certain circumstances was
convertible at our option into common stock if the average trading price for any
thirty-day trading period is equal to or greater than $21.60 per share. Proceeds
from the Series E preferred Stock were used to fund a portion of our capital
contribution to Plains All American Inc. to acquire the Celeron Companies (see
Note 6). At December 31, 1999, there were 177,626 shares outstanding.

 Series F Cumulative Convertible Preferred Stock

  On December 14, 1999, we sold in a private placement 50,000 shares of our
Series F Cumulative Convertible Preferred Stock (the "Series F Preferred Stock")
for $50.0 million. Each share of the Series F Preferred Stock has a stated value
of $1,000 per share and bears a dividend of 10% per annum. Dividends are payable
semi-annually in either cash or additional shares of Series F Preferred Stock at
our option and are cumulative from the date of issue. Dividends paid in
additional shares of Series F Preferred Stock are limited to an aggregate of six
dividend periods. Each share of Series F Preferred Stock is convertible into
81.63 shares of common stock (an initial effective conversion price of $12.25
per share) and in certain circumstances may be converted at our option into
common stock if the average trading price for any sixty-day trading period is
equal to or greater than $21.60 per share. After December 15, 2003, the Series F
Preferred Stock is redeemable at our option at 110% of stated value through
December 15, 2004 and at declining amounts thereafter. If not previously
redeemed or converted, the Series F Preferred Stock is required to be redeemed
in 2007. At December 31, 2000 and 1999, there were 50,000 shares outstanding.

  Proceeds from the Series F Preferred Stock were advanced to PAA in connection
with the unauthorized trading losses through the issuance of $114.0 million of
subordinated debt, which was repaid to us in May 2000 (see Note 3). In 2000, we
paid cash dividends of $4.0 million on the Series F Preferred Stock.

Note 9 -- Capital Stock

 Common and Preferred Stock

  We have authorized capital stock consisting of 50.0 million shares of common
stock, $0.10 par value, and 2 million shares of preferred stock, $1.00 par
value. At December 31, 2000 and 1999, there were 17.5 million shares and 17.9
million shares of common stock outstanding, respectively, and 266,171 shares of
preferred stock outstanding.

                                      F-17
<PAGE>

 Stock Warrants and Options

  At December 31, 2000, we had warrants outstanding which entitle the holders
thereof to purchase an aggregate 150,000 shares of common stock at $25.00 per
share expiring in 2002. Also outstanding at December 31, 1999 were warrants
which entitled the holders to purchase an aggregate of 101,350 shares of common
stock at $7.50 per share. These warrants were exercised in 2000. We have various
stock option plans for our employees and directors (see Note 15).

 Series D Cumulative Convertible Preferred Stock

  In November 1997, we issued 46,600 shares of Series D Cumulative Convertible
Preferred Stock (the "Series D Preferred Stock"). The Series D Preferred Stock
has an aggregate stated value of $23.3 million and is redeemable at our option
at 140% of stated value. If not previously redeemed or converted, the Series D
Preferred Stock will automatically convert into 932,000 shares of common stock
in 2012. Each share of the Series D Preferred Stock has a stated value of $500
and is convertible into common stock at a ratio of $25.00 of stated value for
each share of Common Stock to be issued. The Series D Preferred Stock was
initially recorded at $20.5 million, a discount of $2.8 million from the stated
value of $23.3 million. Commencing January 1, 2000, the Series D Preferred Stock
bears an annual dividend of $30.00 per share. Prior to this date, no dividends
were accrued and the discount was amortized to retained earnings through
December 31, 1999.

  During 2000, we paid cash dividends of approximately $1.0 million on the
Series D Preferred Stock. On January 2, 2001, we paid the fourth quarter 2000
cash dividend in the amount of $350,000 on the Series D Preferred Stock.

 Series H Convertible Preferred Stock

  Pursuant to the exchange offer discussed above (see Note 8), 169,571 shares of
Series G Preferred Stock had been exchanged for our new Series H Preferred Stock
as of December 28, 2000. The new Series H Preferred Stock is convertible into
the same number of shares of common stock as the Series G Preferred Stock (33.33
shares of common), but does not bear a dividend and does not contain a mandatory
redemption feature. In addition, if not earlier converted or exchanged, the
Series H Preferred Stock will automatically convert into common stock on
September 30, 2001.

 Treasury Stock

  In 2000, our Board of Directors authorized the repurchase of up to two million
shares of our common stock. As of December 31, 2000, we had repurchased 1.3
million common shares at a cost of $23.6 million.

NOTE 10 -- EARNINGS PER SHARE

  The following is a reconciliation of the numerators and the denominators of
the basic and diluted earnings per share computations for income (loss) from
continuing operations before extraordinary items and the cumulative effect of
accounting change for the years ended December 31, 2000, 1999 and 1998 (in
thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                             For the Year Ended December 31,
                           -----------------------------------------------------------------------------------------------------
                                        2000                              1999                                1998
                           ------------------------------   -------------------------------     -------------------------------
                            Income      Shares      Per      Income       Shares      Per        Income       Shares      Per
                           (Numera-    (Denomi-    Share    (Numera-     (Denomi-    Share      (Numera-     (Denomi-    Share
                             tor)        nator)    Amount     tor)        nator)     Amount       tor)        nator)     Amount
                           ----------  ----------  ------   ---------  -----------  -------     ---------    --------   -------
<S>                        <C>         <C>         <C>      <C>          <C>         <C>        <C>          <C>         <C>
Income (loss) before
  extraordinary item        $ 45,924                         $(24,787)                           $(62,346)
  and cumulative effect
  of accounting change
Less:  preferred
  stock dividends            (14,725)                         (10,026)                             (4,762)
                             -------                          -------                             -------
Income (loss) available
  to common
  stockholders                31,199      17,845     $1.75    (34,813)     17,262     $(2.02)     (67,108)     16,816     $(3.99)
                                                     =====                            ======                              ======
Effect of dilutive
  securities:
Preferred stock
  conversion                  14,725      10,673
Employee stock
  options and warrants             -         855                   -           -                        -           -
                            --------      -------            --------      ------                --------      ------
Income (loss) available
  to common
stockholders
  assuming dilution         $ 45,924      29,373     $1.56   $(34,813)     17,262     $(2.02)    $(67,108)     16,816     $(3.99)
                            ========      ======     =====   ========      ======     ======     ========      ======     ======
</TABLE>

                                      F-18
<PAGE>

  In 1999 and 1998, we recorded net losses and our options and warrants were not
included in the computations of diluted earnings per share because their assumed
conversion was antidilutive. In addition, our preferred stock is convertible
into common stock but was not included in the computation of diluted earnings
per share in 1999 and 1998 because the effect was antidilutive. See Notes 9 and
15 for additional information concerning outstanding options and warrants.

NOTE 11 -- INCOME TAXES

  Our deferred income tax assets and liabilities at December 31, 2000 and 1999
consist of the tax effect of income tax carryforwards and differences related to
the timing of recognition of certain types of costs incurred in both our
upstream and midstream activities as follows (in thousands):

<TABLE>
<CAPTION>
                                                          December 31,
                                                      --------------------
                                                        2000        1999
                                                      --------    --------
<S>                                                   <C>         <C>
U.S. Federal
Deferred tax assets:
    Net operating losses                              $ 64,370    $ 80,267
    Percentage depletion                                 2,450       2,450
    Tax credit carryforwards                             4,662       1,780
    Excess outside tax basis over outside book basis    24,504      15,377
    Other                                                1,669         627
                                                      --------    --------
                                                        97,655     100,501
Deferred tax liabilities:
    Net oil & gas acquisition, exploration and
      development costs                                (42,946)    (28,788)
                                                      --------    --------
    Net deferred tax asset                              54,709      71,713
    Valuation allowance                                 (2,555)     (2,555)
                                                      --------    --------
                                                        52,154      69,158
                                                      --------    --------
States
Deferred tax liability                                  (4,180)     (1,792)
                                                      --------    --------
Net deferred tax assets                               $ 47,974    $ 67,366
                                                      ========    ========
</TABLE>

  At December 31, 2000, we have a net deferred federal tax asset of $52.2
million, primarily attributable to net operating loss ("NOL") carryforwards. The
minimum amount of future taxable income necessary to utilize the NOL
carryforwards is $183.9 million. Based on current levels of pre-tax income,
excluding nonrecurring items, management believes that it is more likely than
not that we will generate taxable income from operations sufficient to realize
the deferred tax asset.

  At December 31, 2000, we have carryforwards of approximately $183.9 million of
regular tax NOLs, $7.0 million of statutory depletion, $2.3 million of
alternative minimum tax credits and $2.4 million of enhanced oil recovery
credits. At December 31, 2000, we had approximately $165.0 million of
alternative minimum tax NOL carryforwards available as a deduction against
future alternative minimum tax income. The NOL carryforwards expire from 2008
through 2019.

  Set forth below is a reconciliation between the income tax provision (benefit)
computed at the United States statutory rate on income (loss) before income
taxes and the income tax provision per the accompanying consolidated statements
of operations (in thousands):

<TABLE>
<CAPTION>
                                                                                  Year Ended December 31,
                                                                             ---------------------------------
                                                                               2000         1999         1998
                                                                             -------     --------     --------
<S>                                                                         <C>         <C>          <C>
U.S. federal income tax provision at statutory rate                          $25,028     $(15,842)    $(37,573)
State income taxes                                                             2,018       (1,298)      (5,252)
Valuation allowance adjustment                                                     -            -       (4,987)
Full cost ceiling test limitation                                                  -       (3,617)       2,903
Other                                                                         (1,463)         278          (96)
                                                                             -------     --------     --------
Income tax expense (benefit) on income before extraordinary item              25,583      (20,479)     (45,005)
Income tax benefit allocated to extraordinary item                            (3,190)        (293)           -
Income tax benefit allocated to cumulative effect of accounting change           (76)           -            -
                                                                             -------     --------     --------
Income tax (benefit) provision                                               $22,317     $(20,772)    $(45,005)
                                                                             =======     ========     ========
</TABLE>

                                      F-19
<PAGE>

  In accordance with certain provisions of the Tax Reform Act of 1986, a change
of greater than 50% of our beneficial ownership within a three-year period (an
"Ownership Change") will place an annual limitation on our ability to utilize
our existing tax carryforwards. Under the Final Treasury Regulations issued by
the Internal Revenue Service, we do not believe that an Ownership Change has
occurred as of December 31, 2000.

NOTE 12 -- EARLY EXTINGUISHMENT OF DEBT

  During 2000, we recognized extraordinary losses, consisting primarily of
unamortized debt issue costs, totaling $5.0 million (net of minority interest of
$7.0 million and deferred tax of $3.2 million) related to the permanent
reduction of the All American Pipeline, L.P. term loan facility and the
refinancing of PAA's credit facilities. In addition, interest and other income
for the year ended December 31, 2000 includes $4.4 million of previously
deferred net gains from terminated interest rate swaps as a result of the debt
extinguishment (see Note 7). The extraordinary loss in 1999 of $0.5 million (net
of minority interest of $0.7 million and deferred tax of $0.3 million) relates
to the write-off of certain debt issue costs and penalties associated with the
prepayment of debt.

NOTE 13 -- RELATED PARTY TRANSACTIONS

 Reimbursement of Expenses of the General Partner and Its Affiliates

  As the general partner for PAA, we have sole responsibility for conducting its
business and managing its operations and we own all of the incentive
distribution rights. Some of our senior executives who currently operate our
business also manage the business of PAA. We do not receive any management fee
or other compensation in connection with the management of PAA's business, but
we are reimbursed for all direct and indirect expenses incurred on its behalf.
For the years ended December 31, 2000 and 1999 and the period from November 23,
1998 to December 31, 1998, we were reimbursed approximately $63.8 million, $44.7
million and $0.5 million, respectively, for direct and indirect expenses on
PAA's behalf. The reimbursed costs consist primarily of employee salaries and
benefits. PAA does not employ any persons to manage its business. These
functions are provided by the employees of the general partner and us.

 Crude Oil Marketing Agreement

  PAA is the exclusive marketer/purchaser for all of our equity crude oil
production. The marketing agreement provides that PAA will purchase for resale
at market prices all of our equity crude oil production for which PAA charges 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 were paid 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.
Prior to the marketing agreement, PAA's predecessor marketed our crude oil
production and that of our subsidiaries and our royalty owners. We were paid
approximately $83.4 million for the purchase of these products for the period
from January 1, 1998 to November 22, 1998. In management's opinion, such
purchases were made at prevailing market prices. PAA's predecessor did not
recognize a profit on the sale of the crude oil purchased from us.

 Financing

  In December 1999, we loaned to PAA $114.0 million, which was repaid in May
2000 (see Note 3). Interest on 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
purchased 1.3 million Class B common units from PAA at $19.125 per unit, the
market value of the common units on May 12, 1999 (see Note 6).

 Long-Term Incentive Plans

  We have adopted the Plains All American Inc. 1998 Long-Term Incentive Plan for
employees and directors of the general partner and its affiliates. 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 the 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. The general partner may, in the future, make additional
grants under the plan. In general, restricted units

                                      F-20
<PAGE>

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 the general partner are eligible
to vest prior to termination of the subordination period.

  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 general partner 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.

  Transaction Grant Agreements In addition to the grants made under the
Restricted Unit Plan described above, the general partner, at no cost to PAA,
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 the 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 2001 and 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 the 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 general partner prior to
January 1, 2002.

  We recognized noncash compensation expense of approximately $2.7 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. This amount is
included in general and administrative expense on the Consolidated Statements of
Operations. There were no transaction grants which vested for 1998.

NOTE 14 -- BENEFIT PLANS

  Effective June 1, 1996, our board of directors adopted a nonqualified
retirement plan (the "Plan") for certain of our officers. Benefits under the
Plan are based on salary at the time of adoption, vest over a 15-year period and
are payable over a 15-year period commencing at age 60. The Plan is unfunded.

  Net pension expense for the years ended December 31, 2000, 1999 and 1998, is
comprised of the following components (in thousands):

<TABLE>
<CAPTION>


                                                     Year Ended December 31,
                                                     -----------------------
                                                      2000    1999    1998
                                                     ------   -----   -----
<S>                                                   <C>     <C>     <C>
Service cost - benefits earned during the period      $  99   $ 109   $  97
Interest on projected benefit obligation                 96      83      74
Amortization of prior service cost                       37      37      37
Unrecognized loss                                         -       6       3
                                                      -----   -----   -----
Net pension expense                                   $ 232   $ 235   $ 211
                                                      =====   =====   =====
</TABLE>

                                      F-21
<PAGE>

  Summarized information of our retirement plan for the periods indicated is as
  follows (in thousands):

<TABLE>
<CAPTION>
                                                                    December 31,
                                                                --------------------
                                                                  2000        1999
                                                                --------    --------
<S>                                                             <C>         <C>
CHANGE IN BENEFIT OBLIGATION:
 Benefit obligation at beginning of year                         $ 1,233     $ 1,280
 Service cost                                                         99         109
 Interest cost                                                        96          83
 Special termination benefits                                        175           -
 Actuarial (gains) losses                                            218        (239)
                                                                 -------     -------
 Benefit obligation at end of year                               $ 1,821     $ 1,233

AMOUNTS RECOGNIZED IN THE CONSOLIDATED BALANCE SHEETS:
 Projected benefit obligation for service rendered to date       $ 1,821     $ 1,233
 Plan assets at fair value                                             -           -
                                                                 -------     -------
 Fair value of plan assets in excess of benefit obligation        (1,821)     (1,233)
 Unrecognized (gain) loss                                            185         (34)
 Unrecognized prior service costs                                    508         545
 Adjustment to recognize minimum liability                          (693)       (511)
                                                                 -------     -------
 Net amount recognized                                           $(1,821)    $(1,233)
                                                                 =======     =======
</TABLE>

  The weighted-average discount rate used in determining the projected benefit
obligation was 7.5% and 7.8% for the years ended December 31, 2000 and 1999,
respectively.

  We also maintain a 401(k) defined contribution plan whereby we 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 $1.4 million, $1.0
million and $0.5 million, respectively.

NOTE 15 -- STOCK COMPENSATION PLANS

  Historically, we have used stock options as a long-term incentive for our
employees, officers and directors under various stock option plans. The exercise
price of options granted to employees is equal to or greater than the market
price of the underlying stock on the date of grant. Accordingly, consistent with
the provisions of APB 25, no compensation expense has been recognized in the
accompanying financial statements.

  We have options outstanding under our 1996, 1992 and 1991 plans, under which a
maximum of 3.5 million shares of common stock were reserved for issuance.
Generally, terms of the options provide for an exercise price of not less than
the market price of our stock on the date of the grant, a pro rata vesting
period of two to four years and an exercise period of five to ten years.

  We have outstanding performance options to purchase a total of 500,000 shares
of common stock which were granted to two executive officers. Terms of the
options provide for an exercise price of $13.50, the market price on the date of
grant, and an exercise period ending in August 2001. The performance options
vest when the price of our common stock trades at or above $24.00 per share for
any 20 trading days in any 30 consecutive trading day period or upon a change in
control if certain conditions are met.

                                      F-22
<PAGE>

  A summary of the status of our stock options as of December 31, 2000, 1999,
and 1998, and changes during the years ending on those dates are presented
below:

<TABLE>
<CAPTION>
                                                    2000                 1999                  1998
                                             -------------------  -------------------  --------------------
                                                       WEIGHTED             WEIGHTED               WEIGHTED
                                                       AVERAGE              AVERAGE                AVERAGE
                                             SHARES    EXERCISE   SHARES    EXERCISE    SHARES     EXERCISE
              FIXED OPTIONS                   (000)     PRICE     (000)      PRICE      (000)        PRICE
     ---------------------------------       ------   ---------   ------   ---------   --------   ---------
     <S>                                     <C>       <C>        <C>       <C>        <C>         <C>
      Outstanding at beginning of year        2,811     $ 11.06    2,749     $ 10.53      2,614     $  9.50
      Granted                                   412       13.91      237       15.09        333       16.62
      Exercised                                (444)       6.96     (158)       7.94       (179)       6.71
      Forfeited                                 (37)      14.37      (17)       9.93        (19)      11.36
                                             ------               ------               --------
      Outstanding at end of year              2,742     $ 12.11    2,811     $ 11.06      2,749     $ 10.53
                                             ======               ======               ========
      Options exercisable at year-end         1,708     $ 11.07    1,836     $  9.50      1,646     $  8.53
                                             ======               ======               ========
      Weighted-average fair value of
       options granted during the year       $  5.39              $ 5.40                $  4.93
</TABLE>

    In October 1995, the Financial Accounting Standards Board issued SFAS 123
which established financial accounting and reporting standards for stock-based
employee compensation. The pronouncement defines a fair value based method of
accounting for an employee stock option or similar equity instrument. SFAS 123
also allows an entity to continue to measure compensation cost for those
instruments using the intrinsic value-based method of accounting prescribed by
APB 25. We have elected to follow APB 25 and related interpretations in
accounting for our employee stock options because, as discussed below, the
alternative fair value accounting provided for under SFAS 123 requires the use
of option valuation models that were not developed for use in valuing employee
stock options. Under APB 25, because the exercise price of our employee stock
options equals the market price of the underlying stock on the date of grant, no
compensation expense has been recognized in the accompanying financial
statements. We will recognize compensation expense under APB 25 in the future
for the performance options described above, if certain conditions are met and
the options vest.

    Pro forma information regarding net income (loss) and earnings per share is
required by SFAS 123 and has been determined as if we had accounted for our
employee stock options under the fair value method as provided therein. The fair
value for the options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for grants
in 2000, 1999 and 1998: risk-free interest rates of 6.3% for 2000, 5.1% for 1999
and 5.6% for 1998; a volatility factor of the expected market price of our
common stock of .50 for 2000, .50 for 1999 and .38 for 1998; no expected
dividends; and weighted-average expected option lives of 2.6 years in 2000, 2.7
years in 1999 and 2.7 years in 1998.

    The Black-Scholes option valuation model and other existing models were
developed for use in estimating the fair value of traded options that have no
vesting restrictions and are fully transferable. In addition, option valuation
models require the input of and are highly sensitive to subjective assumptions
including the expected stock price volatility. Because our employee stock
options have characteristics significantly different from those of traded
options, and because changes in the subjective input assumptions can materially
affect the fair value estimate, in management's opinion, the existing models do
not provide a reliable single measure of the fair value of its employee stock
options.

    For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The pro forma
information is not meant to be representative of the effects on reported net
income (loss) for future years, because as provided by SFAS 123, the effects of
awards granted before December 31, 1994, are not considered in the pro forma
calculations.

                                      F-23
<PAGE>

  Set forth below is a summary of our net income (loss) before extraordinary
item and earnings per share as reported and pro forma as if the fair value based
method of accounting defined in SFAS 123 had been applied (in thousands, except
per share data).
<TABLE>
<CAPTION>

                                                             YEAR ENDED DECEMBER 31,
                                                         --------------------------------
                                                           2000       1999         1998
                                                         -------    --------     --------
       <S>                                              <C>        <C>          <C>
       As Reported:
         Net income (loss) before extraordinary item
           and cumulative effect of accounting change    $45,924    $(24,787)    $(62,346)
         Net income (loss) per common share, basic          1.75       (2.02)       (3.99)
         Net income (loss) per common share, diluted        1.56       (2.02)       (3.99)

       PRO FORMA:
         Net income (loss) before extraordinary item
           and cumulative effect of accounting change    $45,132    $(25,125)    $(63,054)
         Net income (loss) per common share, basic          1.70       (2.04)       (4.03)
         Net income (loss) per common share, diluted        1.54       (2.04)       (4.03)

</TABLE>

   The following table summarizes information about stock options outstanding at
December 31, 2000 (share amounts in thousands):
<TABLE>
<CAPTION>
                                                            WEIGHTED
                                                             AVERAGE       WEIGHTED                      WEIGHTED
                                              NUMBER        REMAINING       AVERAGE        NUMBER         AVERAGE
                     RANGE OF              OUTSTANDING     CONTRACTUAL     EXERCISE      EXERCISABLE      EXERCISE
                  EXERCISE PRICE           AT 12/31/00         LIFE         PRICE        AT 12/31/00        PRICE
            --------------------------    -------------    -----------    ----------    -------------     --------
              <S>                         <C>              <C>             <C>          <C>               <C>
              $   5.88   to   $  6.75           547         2.7 years       $ 6.26            547          $ 6.26
                  7.50   to      7.81           278         2.2 years         7.61            278            7.61
                 10.50   to     15.88         1,730         2.0 years        14.02            708           14.36
                 17.00   to     19.19           187         2.9 years        18.23            175           18.31
                                            --------                                      --------
              $   5.88   to   $ 19.19         2,742         2.2 years       $12.11          1,708          $11.07
                                            ========                                      ========
</TABLE>
NOTE 16 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION

 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             $7,021
                       2002              4,267
                       2003              4,289
                       2004              4,318
                       2005              4,337
                       Thereafter        2,940

Total expenses related to these commitments for the years ended December 31,
2000, 1999 and 1998 were $7.3 million, $9.3 million and $1.6 million,
respectively.

  In connection with its crude oil marketing, PAA provides 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, PAA had outstanding letters of credit of
approximately $59.7 million. Such letters of credit are secured by PAA's crude
oil inventory and accounts receivable. (see Note 7).

  Under the amended terms of an asset purchase agreement between us and Chevron,
commencing with the year beginning January 1, 2000, and each year thereafter, we
are required to plug and abandon 20% of the then remaining inactive wells, which
currently aggregate approximately 172. To the extent we elect not to plug and
abandon the number of required wells,

                                      F-24
<PAGE>

we are required to escrow an amount equal to the greater of $25,000 per well or
the actual average plugging cost per well in order to provide for the future
plugging and abandonment of such wells. In addition, we are required to expend a
minimum of $600,000 per year in each of the ten years beginning January 1, 1996,
and $300,000 per year in each of the succeeding five years to remediate oil
contaminated soil from existing well sites, provided there are remaining sites
to be remediated. In the event we do not expend the required amounts during a
calendar year, we are required to contribute an amount equal to 125% of the
actual shortfall to an escrow account. We may withdraw amounts from the escrow
account to the extent we expend excess amounts in a future year. Through
December 31, 2000, we have not been required to make contributions to an escrow
account.

  Although we obtained environmental studies on our properties in California,
the Sunniland Trend and the Illinois Basin and we believe that such properties
have been operated in accordance with standard oil field practices, certain of
the fields have been in operation for more than 90 years, and current or future
local, state and federal environmental laws and regulations may require
substantial expenditures to comply with such rules and regulations. In
connection with the purchase of certain of our California properties, we
received a limited indemnity from Chevron for certain conditions if they violate
applicable local, state and federal environmental laws and regulations in effect
on the date of such agreement. We believe that we do not have any material
obligations for operations conducted prior to our acquisition of the properties
from Chevron, other than our obligation to plug existing wells and those
normally associated with customary oil field operations of similarly situated
properties, there can be no assurance that current or future local, state or
federal rules and regulations will not require us to spend material amounts to
comply with such rules and regulations or that any portion of such amounts will
be recoverable under the Chevron indemnity.

  Consistent with normal industry practices, substantially all of our crude oil
and natural gas leases require that, upon termination of economic production,
the working interest owners plug and abandon non-producing wellbores, remove
tanks, production equipment and flow lines and restore the wellsite. We have
estimated that the costs to perform these tasks is approximately $11.0 million,
net of salvage value and other considerations. Such estimated costs are
amortized to expense through the unit-of-production method as a component of
accumulated depreciation, depletion and amortization. Results from operations
for 2000, 1999 and 1998 include $0.5 million, $0.5 million and $0.8 million,
respectively, of expense associated with these estimated future costs. For
valuation and realization purposes of the affected crude oil and natural gas
properties, these estimated future costs are also deducted from estimated future
gross revenues to arrive at the estimated future net revenues and the
Standardized Measure disclosed in Note 20.

  As is common within the industry, we have entered into various commitments and
operating agreements related to the exploration and development of and
production from proved crude oil and natural gas properties and 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.

 Industry Concentration

  Financial instruments which potentially subject us to concentrations of credit
risk consist principally of trade receivables. Our accounts receivable are
primarily from purchasers of crude oil and natural gas products 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 which are
not considered investment grade, unless the credit risk can otherwise be
reduced. The loss of an individual customer would not have a material adverse
effect.

  There are a limited number of alternative methods of transportation for our
production. Substantially all of our California crude oil and natural gas
production and our Sunniland Trend crude oil production is transported by
pipelines, trucks and barges owned by third parties. The inability or
unwillingness of these parties to provide transportation services to us for a
reasonable fee could result in our having to find transportation alternatives,
increased transportation costs or involuntary curtailment of a significant
portion of our crude oil and natural gas production which could have a negative
impact on future results of operations or cash flows.

                                      F-25
<PAGE>

NOTE 17 -- 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, et al.  The suit alleged
that Plains All American Pipeline, L.P. and certain of the 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 the
general partner and us 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 our common stock and options, and is captioned
Koplovitz v. Plains Resources Inc., et al. The second consolidated action is
that filed by purchasers of PAA's 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 PAA reached an agreement with representatives for the plaintiffs for
the settlement of all of the class actions, and in January 2001, PAA deposited
approximately $30.0 million under the terms of the settlement agreement. The
total cost of the settlement to us and PAA, including interest and expenses and
after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million
was allocated to us by agreement between special independent committees of our
board of directors and the board of directors of Plains All American Inc. 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 the general partner, its directors and certain of its officers as
defendants, and allege that the defendants breached the fiduciary duties that
they owed to PAA 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 Sussex v. Plains All American Inc. as the
operative 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 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 for the Southern District of Texas entitled
Fernandez v. Plains All American Inc., et al., naming the 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 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 defendant in
various other legal proceedings. Management does not believe that the outcome of
these legal proceedings, individually and in the aggregate, will have a
materially adverse effect on our financial condition, results of operations or
cash flows.

                                      F-26
<PAGE>

NOTE 18 -- FINANCIAL INSTRUMENTS

 Derivatives

  We utilize derivative financial instruments, as defined in Statement of
Financial Accounting Standards No. 119, "Disclosure About Derivative Financial
Instruments and Fair Value of 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.

  We have entered into various arrangements, using a combination of swaps,
collars and purchased puts and calls, to fix the NYMEX crude oil spot price for
a significant portion of our crude oil production. On December 31, 2000, these
arrangements provided for a NYMEX crude oil price of approximately $23.00 per
barrel on 21,500 barrels per day from January 1, 2001, through December 31,
2001, with full market price participation up to an average of $27.00 per
barrel. For 2002, we have entered into various arrangements that provide for us
to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000
barrels per day with full market price participation up to an average of $24.90
per barrel. Location and quality differentials attributable to our properties
and the cost of the hedges are not included in the foregoing prices. Because of
the quality and location of our crude oil production, these adjustments will
reduce our net price per barrel. The agreements provide for monthly settlement
based on the differential between the agreement price and the actual NYMEX
price. Gains or losses are recognized in the month of related production and are
included in crude oil and natural gas sales. Such contracts resulted in a
reduction of revenues of $79.4 million and $11.1 million for the years ended
December 31, 2000 and 1999, respectively. At December 31, 2000, we had an
unrealized gain of $17.3 million with respect to such contracts and at December
31, 1999, we had an unrealized loss of $22.0 million.

  At December 31, 2000, our hedging activities included crude oil futures
contracts maturing in 2001 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 at December 31, 2000 and
December 31, 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 $240.0 million. The adjustment to interest expense resulting from
interest rate swaps for the years ended December 31, 2000 and 1999 was a $0.3
million gain and a $0.2 million loss, respectively. These instruments are based
on LIBOR margins and provide for (1) a floor of 5% and a ceiling of 6.5% with an
expiration date of February 2001 for $90.0 million notional principal amount (2)
a floor of 6% and a ceiling of 8% with an expiration date of August 2002 for
$125.0 million notional principal amount and (3) a ceiling of 5.7% with an
expiration date of July 2008 for $25.0 million notional principal amount. The
counterparty has the option to terminate the $25.0 million swap in July 2003,
and either party may terminate in July 2005.

 Fair Value of Financial Instruments

  The following disclosure of the estimated fair value of financial instruments
is made in accordance with the requirements of Statement of Financial Accounting
Standards No. 107, Disclosures About Fair Value of Financial Instruments ("SFAS
107"). The estimated fair value amounts have been determined using available
market information and valuation methodologies described below. Considerable
judgment is required in interpreting market data to develop the estimates of
fair value. The use of different market assumptions or valuation methodologies
may have a material effect on the estimated fair value amounts.

                                      F-27
<PAGE>

  The carrying values of items comprising current assets and current liabilities
approximate fair values due to the short-term maturities of these instruments.
Crude oil futures contracts permit settlement by delivery of the crude oil and,
therefore, are not financial instruments, as defined. The carrying amounts and
fair values of our other financial instruments are as follows (in thousands):
<TABLE>
<CAPTION>

                                                                                          December 31,
                                                                       ----------------------------------------------
                                                                                2000                     1999
                                                                       ---------------------     --------------------
                                                                       Carrying       Fair       Carrying      Fair
                                                                        Amount        Value       Amount       Value
                                                                      ----------    --------     --------   ---------
<S>                                                                     <C>         <C>          <C>         <C>
LONG-TERM DEBT:
  Bank debt                                                            $ 347,300    $ 347,300     $ 396,750  $ 396,750
  Subordinated debt                                                      277,543      274,313       277,909    268,125
  Other long-term debt                                                     1,533        1,533         2,044      2,044
  Redeemable Preferred Stock                                              50,000       93,213       138,813    138,813
OFF BALANCE SHEET FINANCIAL INFORMATION:
  Unrealized gain (loss) on crude oil swap  and collar agreements          9,121       17,240             -    (22,048)
  Unrealized gain (loss) on interest rate swap and collar agreements           -         (911)            -      1,048

</TABLE>

  The carrying value of bank debt approximates its fair value as interest rates
are variable, based on prevailing market rates. The fair value of subordinated
debt was based on quoted market prices based on trades of subordinated debt. The
fair value of the redeemable preferred stock was provided by an outside source
at December 31, 2000 and was estimated to be its liquidation value at December
31, 1999. The fair value of the crude oil swap and collar arrangements are
estimated based on quoted prices from independent reporting services compared to
the contract price of the swap or collar. The fair value of the interest rate
swap and collar agreements is based on current termination values or quoted
market prices of comparable contracts at December 31, 2000 and 1999.

NOTE 19 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

  Selected cash payments and noncash activities were as follows (in thousands):
<TABLE>
<CAPTION>

                                                                            YEAR ENDED DECEMBER 31,
                                                                       ----------------------------------
                                                                          2000         1999        1998
                                                                       ----------    ---------   --------
<S>                                                                    <C>           <C>         <C>
Cash paid for interest (net of amount capitalized)                      $  56,154    $  44,329   $  34,546
                                                                        =========    =========   =========
Cash paid for taxes                                                     $     987    $     548   $     183
                                                                        =========    =========   =========
Noncash sources and (uses) of investing and financing activities:
Series D Preferred Stock dividends                                      $       -    $  (1,354)  $  (1,275)
                                                                        =========    =========   =========

Exchange of preferred stock for common stock                            $      62    $      71   $        -
                                                                        =========    =========   =========
Series E Preferred Stock dividends                                      $       -    $  (2,030)  $  (3,487)
                                                                        =========    =========   =========
Tax benefit from exercise of employee stock options                     $   1,901    $     440   $     653
                                                                        =========    =========   =========
</TABLE>


NOTE 20 -- CRUDE OIL AND NATURAL GAS ACTIVITIES

 Costs Incurred

   Our oil and natural gas acquisition, exploration, exploitation and
development activities are conducted in the United States. The following table
summarizes the costs incurred during the last three years (in thousands).


                                                  YEAR ENDED DECEMBER 31,
                                             ---------------------------------
                                               2000        1999        1998
                                             --------    --------    ---------
   Property acquisitions costs:
       Unproved properties                  $     73    $    879    $   6,266
       Proved properties                       2,433       2,880        3,851
   Exploration costs                             872       4,101        1,657
   Exploitation and development costs         77,550      65,119       89,161
                                            --------    --------    ---------
                                            $ 80,928    $ 72,979    $ 100,935
                                            ========    ========    =========

                                      F-28
<PAGE>

 Capitalized Costs

  Under full cost accounting rules as prescribed by the SEC, unamortized costs
of proved crude oil and natural gas properties are subject to a ceiling, which
limits such costs to the Standardized Measure (as described below). At December
31, 1998, the capitalized costs of our proved crude oil and natural gas
properties exceeded the Standardized Measure and we recorded a noncash, after
tax charge to expense of $109.0 million ($173.9 million pre-tax). The following
table presents the aggregate capitalized costs subject to amortization relating
to our crude oil and natural gas acquisition, exploration, exploitation and
development activities, and the aggregate related accumulated DD&A (in
thousands).



                                        DECEMBER 31,
                                   ----------------------
                                    2000         1999
                                   ---------    ---------
         Proved properties         $ 762,245    $ 671,928
         Accumulated DD&A           (408,337)    (387,437)
                                   ---------    ---------
                                   $ 353,908    $ 284,491
                                   =========    =========

  The DD&A rate per equivalent unit of production excluding the writedown in
1998 was $2.31, $2.13 and $3.00 for the years ended December 31, 2000, 1999 and
1998, respectively.

 Costs Not Subject to Amortization

  The following table summarizes the categories of costs which comprise the
amount of unproved properties not subject to amortization (in thousands).

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

        Acquisition costs           $34,087        $42,261    $47,657
        Exploration costs             4,456          4,842      2,467
        Capitalized interest          4,038          4,928      4,421
                                   ---------    ---------    ---------
                                    $42,581        $52,031    $54,545

  Unproved property costs not subject to amortization consist mainly of
acquisition and lease costs and seismic data related to unproved areas. We will
continue to evaluate these properties over the lease terms; however, the timing
of the ultimate evaluation and disposition of a significant portion of the
properties has not been determined. Costs associated with seismic data and all
other costs will become subject to amortization as the prospects to which they
relate are evaluated. Approximately 11%, 16% and 19% of the balance in unproved
properties at December 31, 2000, related to additions made in 2000, 1999 and
1998, respectively.

  During 2000, 1999 and 1998, we capitalized $4.4 million, $4.4 million and $3.7
million, respectively, of interest related to the costs of unproved properties
in the process of development.

 Supplemental Reserve Information (Unaudited)

  The following information summarizes our net proved reserves of crude oil
(including condensate and natural gas liquids) and natural gas and the present
values thereof for the three years ended December 31, 2000. The following
reserve information is based upon reports of the independent petroleum
consulting firms of H.J. Gruy and Company, Netherland Sewell & Associates, Inc.,
and Ryder Scott Company in 2000, 1999 and 1998. The estimates are in accordance
with regulations prescribed by the SEC.

  In management's opinion, the reserve estimates presented herein, in accordance
with generally accepted engineering and evaluation principles consistently
applied, are believed to be reasonable. However, there are numerous
uncertainties inherent in estimating quantities and values of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond our control. Reserve engineering is
a subjective process of estimating the recovery from underground accumulations
of crude oil and natural gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. Because all
reserve estimates are to some degree speculative, the quantities of crude oil
and natural gas that are ultimately recovered, production and operating costs,
the amount and timing of future development expenditures and

                                      F-29
<PAGE>

future crude oil and natural gas sales prices may all differ from those assumed
in these estimates. In addition, different reserve engineers may make different
estimates of reserve quantities and cash flows based upon the same available
data. Therefore, the Standardized Measure shown below represents estimates only
and should not be construed as the current market value of the estimated crude
oil and natural gas reserves attributable to our properties. In this regard, the
information set forth in the following tables includes revisions of reserve
estimates attributable to proved properties included in the preceding year's
estimates. Such revisions reflect additional information from subsequent
exploitation and development activities, production history of the properties
involved and any adjustments in the projected economic life of such properties
resulting from changes in product prices.

  Decreases in the prices of crude oil and natural gas have had, and could have
in the future, an adverse effect on the carrying value of our proved reserves
and our revenues, profitability and cash flow. Almost all of our reserve base
(approximately 94% of year-end 2000 reserve volumes) is comprised of crude oil
properties that are sensitive to crude oil price volatility.

 Estimated Quantities of Crude Oil and Natural Gas Reserves (Unaudited)

  The following table sets forth certain data pertaining to our proved and
proved developed reserves for the three years ended December 31, 2000 (in
thousands).

<TABLE>
<CAPTION>

                                                      AS OF OR FOR THE YEAR ENDED DECEMBER 31,
                                        ---------------------------------------------------------------------
                                                2000                    1999                   1998
                                        ---------------------   ---------------------   ---------------------
                                           Oil         Gas         Oil         Gas         Oil         Gas
                                          (Bbl)       (Mcf)       (Bbl)       (Mcf)       (Bbl)       (Mcf)
                                        ---------   ---------   ---------   ---------   ---------   ---------
<S>                                     <C>         <C>         <C>         <C>         <C>         <C>
PROVED RESERVES
  Beginning balance                       218,922      90,873     120,208      86,781     151,627      60,350
  Revision of previous estimates           (9,834)     (3,597)     62,895      (8,234)    (46,282)      2,925
  Extensions, discoveries, improved
    recovery and other additions           22,429       9,252      37,393      15,488      14,729      29,306
  Sale of reserves in-place                     -           -           -           -           -      (2,799)
  Purchase of reserves in-place                 -           -       6,442           -       7,709           -
  Production                               (8,355)     (3,042)     (8,016)     (3,162)     (7,575)     (3,001)
                                        ---------   ---------   ---------   ---------   ---------   ---------
  Ending balance                          223,162      93,486     218,922      90,873     120,208      86,781
                                        =========   =========   =========   =========   =========   =========
PROVED DEVELOPED RESERVES
  Beginning balance                       120,141      49,255      73,264      58,445      99,193      38,233
                                        =========   =========   =========   =========   =========   =========
  Ending balance                          123,532      52,184     120,141      49,255      73,264      58,445
                                        =========   =========   =========   =========   =========   =========
</TABLE>
 Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

  The Standardized Measure of discounted future net cash flows relating to
proved crude oil and natural gas reserves is presented below (in thousands):


                                                     DECEMBER 31,
                                        ---------------------------------------
                                             2000           1999           1998
                                        -----------    -----------   ----------

   Future cash inflows                  $ 6,057,344    $ 4,837,010   $1,102,863
   Future development costs                (275,862)      (231,914)    (117,924)
   Future production expense             (2,875,301)    (1,758,572)    (546,091)
   Future income tax expense               (887,107)      (845,133)           -
                                        -----------    -----------   ----------
   Future net cash flows                  2,019,074      2,001,391      438,848
   Discounted at 10% per year            (1,099,413)    (1,073,591)    (211,905)
                                        -----------    -----------   ----------
   Standardized measure of
    discounted future net cash flows    $   919,661    $   927,800   $  226,943
                                        ===========    ===========   ==========

  The Standardized Measure of discounted future net cash flows (discounted at
10%) from production of proved reserves was developed as follows:

  1. An estimate was made of the quantity of proved reserves and the future
     periods in which they are expected to be produced based on year-end
     economic conditions.
  2. In accordance with SEC guidelines, the engineers' estimates of future net
     revenues from our proved properties and the present value thereof are made
     using crude oil and natural gas sales prices in effect as of the dates of
     such estimates and are held constant throughout the life of the properties,
     except where such guidelines permit alternate

                                      F-30
<PAGE>

     treatment, including the use of fixed and determinable contractual price
     escalations. We have entered into various fixed price and floating price
     collar arrangements to fix or limit the NYMEX crude oil price for a
     significant portion of our crude oil production. Arrangements in effect at
     December 31, 2000 are discussed in Note 18. Such arrangements are not
     reflected in the reserve reports. The overall average year-end prices used
     in the reserve reports as of December 31, 2000, were $21.02 per barrel of
     crude oil, condensate and natural gas liquids and $14.63 per Mcf of natural
     gas.
  3. The future gross revenue streams were reduced by estimated future operating
     costs (including production and ad valorem taxes) and future development
     and abandonment costs, all of which were based on current costs.

  4. The reports reflect the pre-tax Present Value of Proved Reserves to be $1.3
     billion, $1.2 billion and $226.9 million at December 31, 2000, 1999 and
     1998, respectively. SFAS No. 69 requires us to further reduce these
     estimates by an amount equal to the present value of estimated income taxes
     which might be payable by us in future years to arrive at the Standardized
     Measure. Future income taxes were calculated by applying the statutory
     federal and state income tax rate to pre-tax future net cash flows, net of
     the tax basis of the properties involved and utilization of available tax
     carryforwards related to oil and gas operations.

  The principal sources of changes in the Standardized Measure of the future net
cash flows for the three years ended December  31, 2000, are as follows (in
thousands):

<TABLE>
<CAPTION>

                                                                                YEAR ENDED DECEMBER 31,
                                                                           -----------------------------------
                                                                              2000         1999        1998
                                                                           ---------    ---------    ---------
<S>                                                                       <C>          <C>          <C>
 Balance, beginning of year                                               $ 927,800    $ 226,943    $ 411,823
 Sales, net of production expenses                                         (166,571)     (60,578)     (51,927)
 Net change in sales and transfer prices, net of production expenses        108,977      580,890     (288,320)
 Changes in estimated future development costs                              (14,593)     (52,951)      42,858
 Extensions, discoveries and improved recovery, net of costs                141,638      112,573       21,095
 Previously estimated development costs incurred during the year             31,363       22,842       25,501
 Purchase of reserves in-place                                                    -       53,724       14,173
 Sales of reserves in-place                                                       -            -       (1,151)
 Revision of quantity estimates                                            (104,200)     404,705      (91,942)
 Accretion of discount                                                      115,605       22,694       51,099
 Net change in income taxes                                                (107,485)    (318,249)      99,170
 Changes in estimated timing of production and other                        (12,873)     (64,793)      (5,436)
                                                                          ---------    ---------    ---------
 Balance, end of year                                                     $ 919,661    $ 927,800    $ 226,943
                                                                          =========    =========    =========
</TABLE>

 Results of Operations for Oil and Gas Producing Activities

  The results of operations from oil and gas producing activities below exclude
non-oil and gas revenues, general and administrative expenses, interest charges,
interest income and interest capitalized. Income tax (expense) or benefit was
determined by applying the statutory rates to pretax operating results (in
thousands).

<TABLE>
<CAPTION>
                                                                       YEAR ENDED DECEMBER 31,
                                                                  -----------------------------------
                                                                    2000         1999        1998
                                                                  ---------    ---------    ---------
<S>                                                              <C>          <C>          <C>

Revenues from oil and gas producing activities                     $149,342     $116,223    $ 102,754
Production costs                                                    (62,140)     (55,645)     (50,827)
Depreciation, depletion and amortization                            (47,221)     (36,998)     (31,020)
Reduction in carrying cost of oil and natural gas properties              -            -     (173,874)
Income tax (expense) benefit                                        (15,593)      (9,196)      59,657
                                                                  ---------    ---------    ---------
Results of operations from producing activities
(excluding corporate overhead and interest costs)                  $ 24,388     $ 14,384    $ (93,310)
                                                                  =========    =========    =========
</TABLE>

NOTE 21 - SUBSEQUENT EVENTS

 Acquisitions

  Murphy Oil Company Ltd. Midstream Operations

  On March 1, 2001, PAA 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

                                      F-31
<PAGE>

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

  PAA has 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
PAA's 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.

NOTE 22--QUARTERLY FINANCIAL DATA (UNAUDITED)

  The following table shows summary financial data for 2000 and 1999 (in
thousands, except per share data):

<TABLE>
<CAPTION>
                                                     FIRST         SECOND          THIRD          FOURTH
                                                    QUARTER        QUARTER        QUARTER       QUARTER (1)      TOTAL
                                                  ----------     ----------     ----------     ------------    -----------
<S>                                               <C>            <C>            <C>            <C>             <C>
2000 (RESTATED) (2)
Revenues, as reclassified (3)                     $2,087,685     $1,427,044     $1,542,463      $1,573,393     $ 6,630,585
Operating profit (4)                                  53,502         54,400         48,706          55,660         212,268
Net income before extraordinary
  item and cumulative effect of
  accounting change                                   21,268          8,992          7,026          8,638          45,924
Extraordinary item                                    (1,365)        (3,623)             -              -          (4,988)
Cumulative effect of accounting change                  (121)             -              -              -            (121)
Net income                                            19,782          5,369          7,026          8,638          40,815
Basic EPS
  Before extraordinary item and cumulative              0.98           0.29           0.19           0.29            1.75
    effect of accounting change
  Extraordinary item                                   (0.08)         (0.20)             -              -           (0.28)
  Cumulative effect of accounting change                   -              -              -              -           (0.01)
  After extraordinary item and cumulative
    effect of accounting change                         0.90           0.09           0.19           0.29            1.46
Diluted EPS
  Before extraordinary item and cumulative              0.72           0.28           0.18           0.27            1.56
    effect of accounting change
  Extraordinary item                                   (0.05)         (0.19)             -              -           (0.17)
  Cumulative effect of accounting change                   -              -              -              -               -
  After extraordinary item and cumulative
    effect of accounting change                         0.67           0.09           0.18           0.27            1.39

                                                                                               Table continued on following page
</TABLE>

                                      F-32
<PAGE>

<TABLE>
<CAPTION>
                                                     FIRST         SECOND          THIRD          FOURTH
                                                    QUARTER        QUARTER        QUARTER       QUARTER (1)      TOTAL
                                                  ----------     ----------     ----------     ------------    -----------
<S>                                               <C>            <C>            <C>            <C>             <C>
2000 (AS PREVIOUSLY REPORTED)
Revenues                                          $1,039,941     $  729,300     $  743,243
Operating profit (4)                                  53,959         54,455         48,229
Net income before extraordinary item                  21,478          9,070          6,734
Extraordinary item                                    (1,365)        (3,623)             -
Net income                                            20,113          5,447          6,734
Basic EPS
  Before extraordinary item                             0.99           0.30           0.17
  Extraordinary item                                   (0.08)         (0.20)             -
  After extraordinary item                              0.91           0.10           0.17
Diluted EPS
  Before extraordinary item                             0.73           0.29           0.16
  Extraordinary item                                   (0.05)         (0.20)             -
  After extraordinary item                              0.68           0.09           0.16
</TABLE>

<TABLE>
<CAPTION>
 <S>                                               <C>            <C>            <C>            <C>             <C>
1999
Revenues, as reclassified (3)                     $1,134,601     $2,537,431     $3,005,993     $4,252,890     $10,930,915  (5)
Revenues, as previously reported                     476,971        887,277      1,133,519      2,262,617       4,760,384  (5)
Operating profit (loss) (4)                            7,638         17,966        (21,624)        15,542          19,522  (5)
Net income (loss) before extraordinary item           (5,161)        (3,116)       (20,047)         3,537         (24,787)
Extraordinary item                                         -              -              -           (544)           (544)
Net income (loss)                                     (5,161)        (3,116)       (20,047)         2,993         (25,331)
Basic and diluted EPS
  Before extraordinary item                            (0.45)         (0.33)         (1.30)          0.05           (2.02)
  Extraordinary item                                       -              -              -          (0.03)          (0.03)
  After extraordinary item                             (0.45)         (0.33)         (1.30)          0.02           (2.05)

</TABLE>
------------------
(1)  For 2000, includes a $5.0 million charge to reserve for potentially
     uncollectible accounts receivable.
(2)  2000 has been restated to reflect the adoption of SAB 101. The effect of
     this change in accounting for crude oil inventories on prior periods is
     deminimus.
(3)  These amounts represent the reclassification from previously reported
     amounts due to the adoption of EITF 99-19 and are included in revenues
     above (see Note 2).
(4)  Includes the effects of the unauthorized trading losses for the third and
     fourth quarters of 2000 and all quarters of 1999 (see Note 3).
(5)  Excludes a net gain of $9.8 million related to PAA's unit offerings in
     1999.

                                      F-33
<PAGE>

NOTE 23 -- OPERATING SEGMENTS

  Our operations consist of two operating segments:  (1) Upstream Operations -
engages in the acquisition, exploitation, development, exploration and
production of crude oil and natural gas and (2) Midstream Operations - engages
in pipeline transportation, purchases and resales of crude oil at various points
along the distribution chain and the leasing of certain terminalling and storage
assets. The accounting policies of the segments are the same as those described
in the summary of significant accounting policies (see Note 1). We evaluate
segment performance based on gross margin, gross profit and income before income
taxes and extraordinary items.
<TABLE>
<CAPTION>


(IN THOUSANDS)                                                             UPSTREAM     MIDSTREAM (a)       TOTAL
 -------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>          <C>             <C>
 2000
 Revenues:
   External customers                                                      $ 149,342     $ 6,425,644     $ 6,574,986
   Intersegment (b)                                                                -         215,543         215,543
   Gain on sale of assets                                                          -          48,188          48,188
   Interest and other income (expense)                                        (3,468)         10,879           7,411
                                                                           ---------     -----------     -----------
     Total revenues of reportable segments                                 $ 145,874     $ 6,700,254     $ 6,846,128
                                                                           =========     ===========     ===========
 Segment gross margin (c)                                                  $  86,202     $   126,066     $   212,268
 Segment gross profit (d)                                                     76,297          85,195         161,492
 Segment income (loss) before income taxes, extraordinary item
   and cumulative effect of accounting change                                 23,009          91,033         114,042
 Interest expense                                                             27,346          28,482          55,828
 Depreciation, depletion and amortization                                     22,474          24,747          47,221
 Income tax expense                                                            6,503          19,080          25,583
 Extraordinary item, net of tax and minority interest                              -          (4,988)         (4,988)
 Capital expenditures                                                         81,475          12,603          94,078
 Assets                                                                      458,678         935,651       1,394,329
 -------------------------------------------------------------------------------------------------------------------
 1999
 Revenues:
   External customers                                                      $ 116,223     $10,796,998     $10,913,221
   Intersegment (b)                                                                -          75,454          75,454
   Gain on sale of assets                                                          -          16,457          16,457
   Interest and other income                                                     241          10,783          11,024
                                                                           ---------     -----------     -----------
     Total revenues of reportable segments                                 $ 116,464     $10,899,692     $11,016,156
                                                                           =========     ===========     ===========
 Segment gross margin (c)                                                  $  60,578     $   (58,750)    $     1,828
 Segment gross profit (d)                                                     52,775         (82,349)        (29,574)
 Segment income (loss) before income taxes and extraordinary item              8,132         (93,601)        (85,469)
 Interest expense                                                             25,298          21,080          46,378
 Depreciation, depletion and amortization                                     19,586          17,412          36,998
 Income tax benefit                                                            1,635          18,844          20,479
 Extraordinary item, net of tax and minority interest                              -            (544)           (544)
 Capital expenditures                                                         77,899         189,286         267,185
 Assets                                                                      445,921       1,243,639       1,689,560
 -------------------------------------------------------------------------------------------------------------------
 1998
 Revenues:
   External customers                                                      $ 102,754     $ 3,454,635     $ 3,557,389
   Intersegment (b)                                                                -          62,756          62,756
   Interest and other income                                                     250             584             834
                                                                           ---------     -----------     -----------
     Total revenues of reportable segments                                 $ 103,004     $ 3,517,975     $ 3,620,979
                                                                           =========     ===========     ===========
 Segment gross margin (c) (e)                                              $  51,927     $    31,261     $    83,188
 Segment gross profit (d) (e)                                                 46,446          25,964          72,410
 Segment income (loss) before income taxes and extraordinary item (e)       (175,926)          8,546        (167,380)
 Interest expense                                                             23,099          12,631          35,730
 Depreciation, depletion and amortization                                    199,523           5,371         204,894
 Income tax expense                                                          (33,732)        (11,273)        (45,005)
 Capital expenditures                                                        100,935         405,508         506,443
 Assets                                                                      365,652         607,186         972,838

                                                                                           Footnotes on following page
</TABLE>

                                      F-34
<PAGE>

(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 1998, revenues have been
    reclassified by $2.5 billion, $6.2 billion $2.3 billion, respectively.
(b) Intersegment revenues and transfers were conducted on an arm's-length
    basis.
(c) Gross margin is calculated as operating revenues less operating expenses.
(d) Gross profit is calculated as operating revenues less operating expenses
    and general and administrative expenses.
(e) Differences between segment totals and company totals represent the net
    gain of $60.8 million recorded upon the formation of PAA, which was not
    allocated to segments.

  The following table reconciles segment revenues to amounts reported in our
financial statements:

<TABLE>
<CAPTION>


                                                       FOR THE YEAR ENDED DECEMBER 31,
                                                  -----------------------------------------
                                                     2000           1999            1998
                                                  ----------     -----------     ----------
<S>                                              <C>            <C>             <C>
Revenues of reportable segments                   $6,846,128     $11,016,156     $3,620,979
Intersegment                                        (215,543)        (75,454)       (62,756)
Net gain recorded upon the formation of PAA
   not allocated to reportable segments                    -               -         60,815
                                                  ----------     -----------     ----------
Total company revenues                            $6,630,585     $10,940,702     $3,619,038
                                                  ==========     ===========     ==========

</TABLE>
  Customers accounting for more than 10% of consolidated sales for the periods
indicated are as follows:
<TABLE>
<CAPTION>


                                                                        PERRCENTAGE OF CONSOLIDATED SALES
                                                                        ---------------------------------
                                                                             YEAR ENDED DECEMBER 31,
                                                                        ---------------------------------
CUSTOMER                                                                  2000         1999        1998
                                                                        --------     --------    --------
<S>                                                                      <C>         <C>         <C>
Marathon Ashland Petroleum (1)                                              12%         -           -
Sempra Energy Trading Corporation (1)                                       -           22%         27%
Koch Oil Company (1)                                                        -           18%         15%

                                                                     PERCENTAGE OF UPSTREAM OIL AND GAS SALES (2)
                                                                     -------------------------------------------
Chevron                                                                     43%         39%         -
Equiva Trading Company                                                      23%         -           -
Tosco Refining Company                                                      -           19%         50%
Conoco Inc.                                                                 -           11%         -
Scurlock Permian LLC                                                        -           -           17%
Marathon Ashland Petroleum                                                  13%         16%         -

</TABLE>
--------------
(1)  These customers pertain to our midstream segment. Represents percentage of
     oil and gas sales revenues plus marketing, transportation, storage and
     terminalling revenues.
(2)  PAA is the exclusive marketer/purchaser for all our equity crude oil
     production. These percentages represent the entities that purchased our
     equity crude production from PAA. We believe that the loss of an individual
     customer would not have a material adverse effect on our results of
     operations.

NOTE 24 -- CONSOLIDATING FINANCIAL STATEMENTS

  The following financial information presents consolidating financial
statements which include:

  .  the parent company only ("Parent");
  .  the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries");
  .  the nonguarantor subsidiaries on a combined basis ("Nonguarantor
     Subsidiaries");
  .  elimination entries necessary to consolidate the Parent, the Guarantor
     Subsidiaries and the Nonguarantor Subsidiaries; and
  .  Plains Resources Inc. on a consolidated basis.

  These statements are presented because the Series A-E Notes discussed in
Note 7 are not guaranteed by PAA and our consolidated financial statements
include the accounts of PAA.

                                      F-35
<PAGE>

PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (IN THOUSANDS)
DECEMBER 31, 2000

<TABLE>
<CAPTION>
                                                                   GUARANTOR      NONGUARANTOR    INTERCOMPANY
                                                       PARENT     SUBSIDIARIES    SUBSIDIARIES    ELIMINATIONS    CONSOLIDATED
                                                     ---------    ------------    ------------    ------------   -------------
<S>                                                  <C>          <C>             <C>             <C>             <C>
ASSETS

CURRENT ASSETS
Cash and cash equivalents                            $       4       $     597        $  4,479    $          -      $    5,080
Accounts receivable and other                           12,193          15,596         347,696               -         375,485
Current Intercompany advances                                -          17,605         (17,605)              -              -
Inventory                                                    -           8,063          46,781               -          54,844
                                                     ---------    ------------    ------------    ------------   -------------
Total current assets                                    12,197          41,861         381,351               -        435,409
                                                     ---------    ------------    ------------    ------------   -------------
PROPERTY AND EQUIPMENT                                 237,591         570,677         473,471               -       1,281,739
Less allowance for depreciation,
depletion and amortization                            (215,942)       (138,871)        (27,266)        (55,386)       (437,465)
                                                     ---------    ------------    ------------    ------------   -------------
                                                        21,649         431,806         446,205         (55,386)        844,274
                                                     ---------    ------------    ------------    ------------   -------------
INVESTMENTS IN SUBSIDIARIES AND
 INTERCOMPANY ADVANCES                                 389,467        (254,891)         (6,372)       (128,204)              -
                                                     ---------    ------------    ------------    ------------   -------------
OTHER ASSETS                                             8,151          16,005          90,490               -         114,646
                                                     ---------    ------------    ------------    ------------   -------------
                                                     $ 431,464       $ 234,781        $911,674       $(183,590)     $1,394,329
                                                     =========    ============    ============    ============   =============

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable and other current liabilities       $   7,105       $  46,368        $359,823       $      13      $  413,309
Notes payable and other current obligations                  -             511           1,300               -           1,811
                                                     ---------    ------------    ------------    ------------   -------------
Total current liabilities                                7,105          46,879         361,123              13         415,120

BANK DEBT                                               27,300               -               -               -          27,300
BANK DEBT OF A SUBSIDIARY                                    -               -         320,000               -         320,000
SUBORDINATED DEBT                                      277,543               -               -               -         277,543
OTHER LONG-TERM DEBT                                         -           1,533               -               -           1,533
OTHER LONG-TERM LIABILITIES                              2,413               -           1,009               -           3,422
                                                     ---------    ------------    ------------    ------------   -------------
                                                       314,361          48,412         682,132              13       1,044,918
                                                     ---------    ------------    ------------    ------------   -------------
MINORITY INTEREST                                      (70,037)              -         232,216              92         162,271
                                                     ---------    ------------    ------------    ------------   -------------
CUMULATIVE CONVERTIBLE
PREFERRED STOCK, STATED
AT LIQUIDATION PREFERENCE                               50,000               -               -               -          50,000
                                                     ---------    ------------    ------------    ------------   -------------
NON-REDEEMABLE PREFERRED STOCK,
COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock         23,300               -               -               -          23,300
Series H Cumulative Convertible Preferred Stock         84,785               -               -               -          84,785
Common Stock                                             1,875              78               -             (78)          1,875
Additional paid-in capital                             139,203           3,951          43,393         (47,344)        139,203
Retained earnings (accumulated deficit)                (88,410)        182,340         (46,067)       (136,273)        (88,410)
Treasury stock, at cost                                (23,613)              -               -               -         (23,613)
                                                     ---------    ------------    ------------    ------------   -------------
                                                       137,140         186,369          (2,674)       (183,695)        137,140
                                                     ---------    ------------    ------------    ------------   -------------
                                                     $ 431,464       $ 234,781        $911,674       $(183,590)     $1,394,329
                                                     =========    ============    ============    ============   =============
</TABLE>

                                      F-36
<PAGE>

PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET (IN THOUSANDS)
DECEMBER 31, 1999

<TABLE>
<CAPTION>
                                                                   GUARANTOR      NONGUARANTOR    INTERCOMPANY
                                                       PARENT     SUBSIDIARIES    SUBSIDIARIES    ELIMINATIONS    CONSOLIDATED
                                                     --------     ------------    ------------    ------------   -------------
<S>                                                  <C>          <C>             <C>             <C>             <C>
ASSETS

CURRENT ASSETS
Cash and cash equivalents                            $   9,241       $   5,134      $   53,853    $                 $   68,228
Accounts receivable and other                            1,808          11,221         508,919               -         521,948
Current Intercompany advances                                -          36,415         (36.415)              -               -
Inventory                                                    -           5,652          34,826               -          40,478
Assets held for sale                                         -               -         141,486               -         141,486
                                                     ---------    ------------    ------------    ------------   -------------
Total current assets                                    11,049          58,422         702,669               -        772,140
                                                     ---------    ------------    ------------    ------------   -------------

PROPERTY AND EQUIPMENT                                 235,158         494,279         460,730               -       1,190,167
Less allowance for depreciation,
  depletion and amortization                          (215,463)       (120,016)        (11,649)        (55,386)       (402,514)
                                                     ---------    ------------    ------------    ------------   -------------
                                                        19,695         374,263         449,081         (55,386)        787,653
                                                     ---------    ------------    ------------    ------------   -------------
INVESTMENTS IN SUBSIDIARIES AND
 INTERCOMPANY ADVANCES                                 479,177        (261,013)         (9,268)       (208,896)              -
                                                     ---------    ------------    ------------    ------------   -------------
OTHER ASSETS                                            40,337          14,752          74,678               -         129,767
                                                     ---------    ------------    ------------    ------------   -------------
                                                     $ 550,258       $ 186,424      $1,217,160       $(264,282)     $1,689,560
                                                     =========    ============    ============    ============   =============

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable and other current liabilities       $  23,700       $  35,457      $  487,212       $      24      $  546,393
Notes payable and other current obligations                  -             511         109,369               -         109,880
                                                     ---------    ------------    ------------    ------------   -------------
Total current liabilities                               23,700          35,968         596,581              24         656,273

BANK DEBT                                              137,300               -               -               -         137,300
BANK DEBT OF A SUBSIDIARY                                    -               -         259,450               -         259,450
SUBORDINATED DEBT                                      277,909               -               -               -         277,909
OTHER LONG-TERM DEBT                                         -           2,044         105,000        (105,000)          2,044
OTHER LONG-TERM LIABILITIES                              1,954               -          19,153               -          21,107
                                                     ---------    ------------    ------------    ------------   -------------
                                                       440,863          38,012         980,184        (104,976)      1,354,083
                                                     ---------    ------------    ------------    ------------   -------------
MINORITY INTEREST                                      (70,037)              -         226,082               -         156,045
                                                     ---------    ------------    ------------    ------------   -------------
CUMULATIVE CONVERTIBLE
  PREFERRED STOCK, STATED
  AT LIQUIDATION PREFERENCE                            138,813               -               -               -         138,813
                                                     ---------    ------------    ------------    ------------   -------------
NON-REDEEMABLE PREFERRED STOCK,
  COMMON STOCK AND
  OTHER STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock         23,300               -               -               -          23,300
Common Stock                                             1,792              78               -             (78)          1,792
Additional paid-in capital                             130,027           3,952          43,261         (47,213)        130,027
Retained earnings (accumulated deficit)               (114,500)        144,382         (32,367)       (112,015)       (114,500)
                                                     ---------    ------------    ------------    ------------   -------------
                                                        40,619         148,412          10,894        (159,306)         40,619
                                                     ---------    ------------    ------------    ------------   -------------
                                                     $ 550,258       $ 186,424      $1,217,160       $(264,282)     $1,689,560
                                                     =========    ============    ============    ============   =============
</TABLE>

                                      F-37
<PAGE>

PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, 2000

<TABLE>
<CAPTION>
                                                                        GUARANTOR      NONGUARANTOR    INTERCOMPANY
                                                            PARENT     SUBSIDIARIES    SUBSIDIARIES    ELIMINATIONS    CONSOLIDATED
                                                           --------    ------------    ------------    ------------    ------------
<S>                                                       <C>          <C>             <C>             <C>             <C>
REVENUES
Crude oil and natural gas sales                            $      4        $147,684    $          -       $   1,654      $  149,342
Marketing, transportation, storage and terminalling               -               -       6,641,187        (215,543)      6,425,644
Gain on sale of assets                                                            -          48,188               -          48,188
Interest and other income                                      (737)            331          10,879          (3,062)          7,411
Equity in earnings of subsidiary                             64,115               -               -         (64,115)              -
                                                           --------    ------------    ------------    ------------    ------------
                                                             63,382         148,015       6,700,254        (281,066)      6,630,585
                                                           --------    ------------    ------------    ------------    ------------
EXPENSES
Production expenses                                               -          62,140               -               -          62,140
Marketing, transportation, storage and terminalling               -               -       6,506,504        (213,889)      6,292,615
Unauthorized trading losses and related expenses              1,000               -           6,963               -           7,963
General and administrative                                    2,054           7,851          40,871               -          50,776
Depreciation, depletion and amortization                      3,068          19,406          24,747               -          47,221
Interest expense                                              9,581          20,827          28,482          (3,062)         55,828
                                                           --------    ------------    ------------    ------------    ------------
                                                             15,703         110,224       6,607,567        (216,951)      6,516,543
                                                           --------    ------------    ------------    ------------    ------------
Income (loss) before income taxes, minority interest,
  extraordinary item and cumulative effect
  of accounting change                                       47,679          37,791          92,687         (64,115)        114,042
Minority interest                                                 -               -          42,535               -          42,535
                                                           --------    ------------    ------------    ------------    ------------
Income (loss) before income taxes, extraordinary item
  and cumulative effect of accounting change                 47,679          37,791          50,152         (64,115)         71,507
Income tax expense (benefit):
  Current                                                   (24,094)              -          25,114               -           1,020
  Deferred                                                   30,958            (361)         (6,034)              -          24,563
                                                           --------    ------------    ------------    ------------    ------------
Income (loss) before extraordinary item and
  cumulative effect of accounting change                     40,815          38,152          31,072         (64,115)         45,924
Extraordinary item, net of tax benefit
  and minority interest                                           -               -          (4,988)              -          (4,988)
Cumulative effect of accounting change,
  net of tax benefit                                              -            (121)              -               -            (121)
                                                           --------    ------------    ------------    ------------    ------------
NET INCOME (LOSS)                                            40,815          38,031          26,084         (64,115)         40,815
Less:  cumulative preferred stock dividends                  14,725               -               -               -          14,725
                                                           --------    ------------    ------------    ------------    ------------
NET INCOME (LOSS) AVAILABLE
    TO COMMON STOCKHOLDERS                                 $ 26,090        $ 38,031      $   26,084       $ (64,115)     $   26,090
                                                           ========    ============    ============    ============    ============
</TABLE>

                                      F-38
<PAGE>

PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1999

<TABLE>
<CAPTION>

                                                          GUARANTOR          NONGUARANTOR          INTERCOMPANY
                                           PARENT        SUBSIDIARIES        SUBSIDIARIES          ELIMINATIONS        CONSOLIDATED
                                         ----------      ------------        ------------         -------------        ------------
<S>                                    <C>              <C>              <C>                     <C>                 <C>
REVENUES
Crude oil and natural gas sales            $      -         $114,736         $          -            $  1,487        $   116,223
Marketing, transportation,
 storage and terminalling                         -                -            10,872,452             (75,454)        10,796,998
Gain on PAA unit offering                         -                -                 9,787                   -              9,787
Gain on sale of assets                                             -                16,457                   -             16,457
Interest and other income                       699               89                   996                (547)             1,237
Equity in earnings of
 subsidiary                                 (11,510)               -                     -              11,510                  -
                                         ----------      ------------        --------------       -------------        ------------
                                            (10,811)         114,825            10,899,692             (63,004)        10,940,702
                                         ----------      ------------        --------------       -------------        ------------
EXPENSES
Production expenses                               -           55,645                     -                   -             55,645
Marketing, transportation,
 storage and terminalling                         -                -            10,763,275             (73,967)        10,689,308
Unauthorized trading loss and
 related expenses                                 -                -               166,440                                166,440
General and administrative                    2,311            5,492                23,599                   -             31,402
Depreciation, depletion and
 amortization                                 2,096           17,490                17,412                   -             36,998
Interest expense                              6,994           18,851                21,080                (547)            46,378
                                         ----------      ------------        --------------       -------------        ------------
                                             11,401           97,478            10,991,806             (74,514)        11,026,171
                                         ----------      ------------        --------------       -------------        ------------
Income (loss) before income
 taxes, minority interest and
 extraordinary item                         (22,212)          17,347               (92,114)             11,510            (85,469)
Minority interest                                 -                -               (40,203)                  -            (40,203)
                                         ----------      ------------        --------------       -------------        ------------
Income (loss) before income
 taxes and extraordinary item               (22,212)          17,347               (51,911)             11,510            (45,266)
Income tax expense (benefit):
Current                                        (338)               -                   331                   -                 (7)
Deferred                                      3,457           (4,754)              (19,175)                  -            (20,472)
                                         ----------      ------------        --------------       -------------        ------------
Income (loss) before
 extraordinary item                         (25,331)          22,101               (33,067)             11,510            (24,787)
Extraordinary item, net of tax
 benefit
and minority interest                             -                -                  (544)                  -               (544)
                                         ----------      ------------        --------------       -------------        ------------
NET INCOME (LOSS)                           (25,331)          22,101               (33,611)             11,510            (25,331)
Less:  cumulative preferred
 stock dividends                             10,026                -                     -                   -             10,026
                                         ----------      ------------        --------------       -------------        ------------
NET INCOME (LOSS) AVAILABLE
    TO COMMON STOCKHOLDERS                 $(35,357)        $ 22,101           $   (33,611)           $ 11,510        $   (35,357)
                                         ==========      ============        ==============       =============       =============
</TABLE>

                                      F-39
<PAGE>

PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENT OF OPERATIONS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1998

<TABLE>
<CAPTION>

                                                        GUARANTOR          NONGUARANTOR           INTERCOMPANY
                                      PARENT          SUBSIDIARIES         SUBSIDIARIES           ELIMINATIONS        CONSOLIDATED
                                -----------------     ------------     -------------------       -------------       --------------
<S>                             <C>                  <C>               <C>                     <C>                  <C>
REVENUES
Crude oil and natural gas
 sales                          $               -          $102,634    $                  -             $    120         $  102,754
Marketing, transportation,
 storage and terminalling                       -                 -               3,517,391              (62,756)         3,454,635
Gain on formation of PAA                   60,815                 -                       -                    -             60,815
Interest and other income                      40                76                     718                    -                834
Equity in earnings of
 subsidiary                              (123,738)                -                       -              123,738                  -
                                      ------------       -----------            ------------          -----------        -----------
                                          (62,883)          102,710               3,518,109               61,102          3,619,038
                                      ------------       -----------            ------------          -----------        -----------
 EXPENSES
Production expenses                             -            50,827                       -                    -             50,827
Marketing, transportation,
 storage and terminalling                       -                 -               3,478,910              (62,636)         3,416,274
Unauthorized trading losses
 and related expenses                           -                 -                   7,100                    -              7,100
General and administrative                  1,536             3,946                   5,296                    -             10,778
Depreciation, depletion and
 amortization                               5,521            20,127                   5,372                    -             31,020
Reduction in carrying cost
 of oil and natural gas
 properties                                 9,267            25,738                       -              138,869            173,874
Interest expense                           11,389            11,710                  12,631                    -             35,730
                                      ------------       -----------            ------------          -----------        -----------
                                           27,713           112,348               3,509,309               76,233          3,725,603
                                      ------------       -----------            ------------          -----------        -----------
Income (loss) before income
 taxes and minority interest              (90,596)           (9,638)                  8,800              (15,131)          (106,565)
Minority interest                               -                 -                     786                    -                786
                                      ------------       -----------            ------------          -----------        -----------
Income (loss) before income
 taxes                                    (90,596)           (9,638)                  8,014              (15,131)          (107,351)
Income tax expense (benefit):
Current                                    (3,637)               (3)                  4,502                    -                862
Deferred                                  (24,613)           (9,237)                (12,017)                   -            (45,867)
                                      ------------       -----------            ------------          -----------        -----------
NET INCOME (LOSS)                         (62,346)             (398)                 15,529              (15,131)           (62,346)
Less:  cumulative preferred
 stock dividends                            4,762                 -                       -                    -              4,762
                                      ------------       -----------            ------------          -----------        ----------
NET INCOME (LOSS) AVAILABLE
 TO COMMON STOCKHOLDERS                 $ (67,108)         $   (398)             $   15,529             $(15,131)        $  (67,108)
                                      ============       ===========            ============          ===========        ===========
</TABLE>

                                      F-40
<PAGE>

PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, 2000
<TABLE>
<CAPTION>
                                                                       GUARANTOR      NONGUARANTOR    INTERCOMPANY
                                                           PARENT     SUBSIDIARIES    SUBSIDIARIES    ELIMINATIONS    CONSOLIDATED
                                                        ----------    ------------    ------------    ------------    ------------
<S>                                                      <C>          <C>             <C>             <C>             <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)                                        $  40,815        $ 38,031     $    26,084    $    (64,115)    $    40,815
Adjustments to reconcile net income to net cash
 provided by operating activities:
  Depreciation, depletion, and amortization                  3,068          19,406          24,747               -          47,221
  Gain on sale of assets (Note 6)                                -               -         (48,188)              -         (48,188)
  Minority interest in income of a subsidiary                    -               -          35,566               -          35,566
  Equity earnings in subsidiary                            (64,115)              -               -          64,115               -
  Deferred income tax                                       30,958            (362)         (9,299)              -          21,297
  Noncash compensation expense                                (407)              -           3,089               -           2,682
  Allowance for doubtful accounts                                -               -           5,000               -           5,000
  Other noncash items                                        6,351               -           4,574               -          10,925
Change in assets and liabilities resulting from
 operating activities:
  Accounts receivable and other                            (10,385)         (7,461)        120,497               -         102,651
  Inventory                                                      -          (2,023)        (11,954)              -         (13,977)
  Pipeline linefill                                              -               -         (16,679)              -         (16,679)
  Accounts payable and other current liabilities           (16,595)         34,685        (161,543)              -        (143,453)
  Other long-term liabilities                                  591               -          (8,591)              -          (8,000)
  Advances from (payments to) affiliates                   119,735          (9,889)       (109,846)              -               -
                                                        ----------    ------------    ------------    ------------    ------------
NET CASH FLOWS PROVIDED BY
 (USED IN) OPERATING ACTIVITIES                            110,016          72,387        (146,543)              -          35,860
                                                        ----------    ------------    ------------    ------------    ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for crude oil pipeline, gathering
 and terminal assets                                             -               -         (12,219)              -         (12,219)
Payments for acquisition, exploration,
 and development costs                                      (3,894)        (74,448)           (384)              -         (78,726)
Payments for additions to other property and assets              -          (2,476)           (657)              -          (3,133)
Proceeds from asset sales (Note 6)                               -               -         224,261               -         224,261
                                                        ----------    ------------    ------------    ------------    ------------
NET CASH PROVIDED BY (USED IN)
 INVESTING ACTIVITIES                                       (3,894)        (76,924)        211,001               -         130,183
                                                        ----------    ------------    ------------    ------------    ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt                               264,825               -       1,433,750               -       1,698,575
Proceeds from short-term debt                                    -               -          51,300               -          51,300
Proceeds from sale of capital stock,
 options and warrants                                        2,301               -               -               -           2,301
Principal payments of long-term debt                      (375,336)              -      (1,423,850)              -      (1,799,186)
Principal payments of short-term debt                            -               -        (108,719)              -        (108,719)
Purchase of treasury stock                                 (23,613)              -               -               -         (23,613)
Costs incurred in connection with
 financing arrangements                                          -               -          (6,748)              -          (6,748)
Preferred stock dividends                                  (13,409)              -               -               -         (13,409)
Distribution to unitholders                                 30,133               -         (59,565)              -         (29,432)
Other                                                         (260)              -               -               -            (260)
                                                        ----------    ------------    ------------    ------------    ------------
NET CASH USED IN FINANCING ACTIVITIES                     (115,359)              -        (113,832)              -        (229,191)
                                                        ----------    ------------    ------------    ------------    ------------
Net decrease in cash and cash equivalents                   (9,237)         (4,537)        (49,374)              -         (63,148)
Cash and cash equivalents, beginning of period           $   9,241        $  5,134     $    53,853    $          -          68,228
                                                        ----------    ------------    ------------    ------------    ------------
Cash and cash equivalents, end of period                 $       4        $    597     $     4,479    $                $     5,080
                                                        ==========    ============    ============    ============    ============

</TABLE>

                                      F-41
<PAGE>

PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
                                                                        GUARANTOR     NONGUARANTOR    INTERCOMPANY
                                                           PARENT     SUBSIDIARIES    SUBSIDIARIES    ELIMINATIONS    CONSOLIDATED
                                                          ---------   ------------    ------------   --------------  --------------
<S>                                                      <C>          <C>             <C>             <C>             <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)                                        $ (25,331)       $ 22,101       $ (33,611)       $ 11,510       $ (25,331)
Adjustments to reconcile net income to net cash
 provided by operating activities:
  Depreciation, depletion, and amortization                  2,096          17,490          17,412               -          36,998
  Noncash gains (Note 4 and 6)                                   -               -         (26,244)              -         (26,244)
  Minority interest in income of a subsidiary                    -               -         (40,203)              -         (40,203)
  Equity in earnings of subsidiary                          11,510               -               -         (11,510)              -
  Deferred income tax                                        3,457          (4,754)        (19,175)              -         (20,472)
  Noncash compensation expense                                   -               -           1,013               -           1,013
  Other noncash items                                       (1,108)              -           1,047               -             (61)
Change in assets and liabilities resulting from
 operating activities:
  Accounts receivable and other                               (970)         (1,287)       (224,181)              -        (226,438)
  Inventory                                                      -            (842)         34,772               -          33,930
  Pipeline linefill                                              -               -              (3)              -              (3)
  Accounts payable and other current liabilities             5,275           2,169         164,530               -         171,974
  Other long-term liabilities                                    -               -          18,873               -          18,873
                                                          ---------   ------------    ------------   --------------  --------------
NET CASH FLOWS PROVIDED BY
 (USED IN) OPERATING ACTIVITIES                             (5,071)         34,877        (105,770)              -         (75,964)
                                                          ---------   ------------    ------------   --------------  --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for midstream acquisitions (See Note 6)                 -               -        (176,918)              -        (176,918)
Payments for crude oil pipeline, gathering
 and terminal assets                                             -               -         (12,507)              -         (12,507)
Payments for acquisition, exploration,
 and development costs                                      (3,793)        (74,106)              -               -         (77,899)
Payments for additions to other property and assets           (267)         (2,137)            (68)              -          (2,472)
Proceeds from sale of pipeline linefill                          -               -           3,400               -           3,400
                                                          ---------   ------------    ------------   --------------  --------------
NET CASH USED IN INVESTING ACTIVITIES                       (4,060)        (76,243)       (186,093)              -        (266,396)
                                                          ---------   ------------    ------------   --------------  --------------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates                      (194,902)         46,306         148,396             200               -
Proceeds from long-term debt                               341,250               -         403,721               -         744,971
Proceeds from short-term debt                                    -               -         131,119               -         131,119
Proceeds from sale of capital stock,
 options and warrants                                        5,542               -               -               -           5,542
Proceeds from issuance of preferred stock                   50,000               -               -               -          50,000
Proceeds from issuance of common units (Note 4)            (25,000)              -          75,759               -          50,759
Principal payments of long-term debt                      (180,711)              -        (268,621)              -        (449,332)
Principal payments of short-term debt                            -               -         (82,150)              -         (82,150)
Costs incurred in connection with
 financing arrangements                                     (2,205)              -         (17,243)              -         (19,448)
Preferred stock dividends                                   (4,245)              -               -               -          (4,245)
Distribution to unitholders                                 29,472               -         (51,673)              -         (22,201)
Other                                                         (971)              -               -               -            (971)
                                                          ---------   ------------    ------------   --------------  --------------
NET CASH PROVIDED BY FINANCING ACTIVITIES                   18,230          46,306         339,308             200         404,044
                                                          ---------   ------------    ------------   --------------  --------------
Net increase in cash and cash equivalents                    9,099           4,940          47,445             200          61,684
Cash and cash equivalents, beginning of period                 142             194           6,408            (200)          6,544
                                                          ---------   ------------    ------------   --------------  --------------
Cash and cash equivalents, end of period                 $   9,241        $  5,134       $  53,853    $          -       $  68,228
                                                          =========   ============    ============   ==============  ==============
</TABLE>

                                      F-42
<PAGE>

PLAINS RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS  (IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
                                                                    GUARANTOR      NONGUARANTOR       INTERCOMPANY
                                                     PARENT       SUBSIDIARIES     SUBSIDIARIES       ELIMINATIONS      CONSOLIDATED
                                                   ----------     ------------     ------------       ------------      ------------
<S>                                                <C>            <C>              <C>                <C>               <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)                                  $ (62,346)       $   (398)        $  15,529          $ (15,131)        $ (62,346)
Adjustments to reconcile net income to net cash
 provided by (used in) operating activities:
  Depreciation, depletion, and amortization            5,521          20,127             5,372                  -            31,020
  Reduction in carrying costs of oil and
   natural gas properties                              9,267          25,738                 -            138,869           173,874
  Noncash gain (Note 4 and 6)                        (70,037)              -                 -                  -           (70,037)
  Minority interest in income of a subsidiary              -               -               786                  -               786
  Equity in earnings of subsidiary                   123,738               -                 -           (123,738)                -
  Deferred income tax                                (24,613)         (9,237)          (12,017)                 -           (45,867)
  Other noncash items                                     90               -                 -                  -                90
Change in assets and liabilities resulting from
 operating activities:
  Accounts receivable and other                          275          (3,444)           27,253                  -            24,084
  Inventory                                                8            (924)          (18,141)                 -           (19,057)
  Pipeline linefill                                        -               -            (3,904)                 -            (3,904)
  Accounts payable and other current liabilities       6,232         (10,782)           10,825              2,712             8,987
                                                 -----------     -----------      ------------       ------------      ------------
NET CASH FLOWS PROVIDED BY
 (USED IN) OPERATING ACTIVITIES                      (11,865)         21,080            25,703              2,712            37,630
                                                 -----------     -----------      ------------       ------------      ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for midstream acquisitions (Note 6)               -               -          (394,026)                 -          (394,026)
Payments for crude oil pipeline, gathering
 and terminal assets                                       -               -            (8,131)                 -            (8,131)
Proceeds from the sale of oil and natural
 gas properties                                            -             131                 -                  -               131
Payments for acquisition, exploration,
 and development costs                                     -         (80,318)                -                  -           (80,318)
Payments for additions to other property and
 other assets                                           (510)           (309)             (259)                 -            (1,078)
                                                 -----------     -----------      ------------       ------------      ------------
NET CASH USED IN INVESTING ACTIVITIES                   (510)        (80,496)         (402,416)                 -          (483,422)
                                                 -----------     -----------      ------------       ------------      ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Advances/investments with affiliates                 (54,060)         59,347            (5,287)                 -                 -
Proceeds from long-term debt                         239,260               -           331,300                  -           570,560
Proceeds from short-term debt                              -               -            31,750                  -            31,750
Proceeds from sale of capital stock, options
 and warrants                                            828               -                 -                  -               828
Proceeds from issuance of preferred stock             85,000               -                 -                  -            85,000
Proceeds from issuance of common units                     -               -           241,690                  -           241,690
Distributions upon formation                         241,690               -          (241,690)                 -                 -
Principal payments of long-term debt                (384,260)              -           (39,300)                 -          (423,560)
Principal payments of short-term debt                      -               -           (40,000)                 -           (40,000)
Capital contribution from Parent                    (113,700)              -           113,700                  -                 -
Dividend to Parent                                     3,557               -            (3,557)                 -                 -
Costs incurred in connection with financing
 arrangements                                         (6,138)              -            (6,937)                 -           (13,075)
Other                                                 (4,571)              -                 -                  -            (4,571)
                                                 -----------     -----------      ------------       ------------      ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES              7,606          59,347           381,669                  -           448,622
                                                 -----------     -----------      ------------       ------------      ------------
Net increase (decrease) in cash and cash
 equivalents                                          (4,769)            (69)            4,956              2,712             2,830
Cash and cash equivalents, beginning of period         4,911             263             1,452             (2,912)            3,714
                                                 -----------     -----------      ------------       ------------      ------------
Cash and cash equivalents, end of period           $     142        $    194         $   6,408          $    (200)        $   6,544
                                                 ===========     ===========      ============       ============      ============
</TABLE>

                                      F-43