<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, 1997

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

  For the transition period from __________ to _____________

                        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 Number)

              500 Dallas
            Houston, Texas                                  77002
(Address of principal executive offices)                 (Zip Code)

      Registrant's telephone number, including area code:  (713) 654-1414

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

<TABLE> 
<S>                                             <C> 
       Title of each class:                     Name of each exchange on which registered:
       --------------------                     ------------------------------------------
       Common Stock, par value $.10 per share   American Stock Exchange
</TABLE> 

Securities registered pursuant to Section 12(g) of the Act:  None

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 the filing
requirements for the past 90 days. Yes  [x]   No  [_]

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
$284,421,835 on March 24, 1998 (based on $17 3/8 per share, the last sale
price of the Common Stock as reported on the American Stock Exchange Composite
Tape on such date).

16,744,272 shares of the registrant's Common Stock were outstanding as of March
20, 1998.

DOCUMENTS INCORPORATED BY REFERENCE.  The information required in Part III of
this 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>
 
                                     PART I

ITEM 1.   BUSINESS

          Plains Resources Inc. (the "Company") is an independent energy company
engaged in the acquisition, exploitation, development, exploration and
production of crude oil and natural gas and the marketing, transportation,
terminalling and storage of crude oil.  The Company's upstream oil and natural
gas activities are focused in California in the Los Angeles Basin (the "LA
Basin") and the Arroyo Grande Field (collectively the "California Properties"),
the Sunniland Trend of South Florida (the "Sunniland Trend") and the Illinois
Basin in southern Illinois (the "Illinois Basin").  The Company's midstream
marketing, terminalling and storage activities are concentrated in Oklahoma,
Texas, the Gulf Coast area of Louisiana and California.  The Company's upstream
operations contributed approximately 87% of the Company's earnings before
interest, taxes, depreciation, depletion and amortization ("EBITDA") for the
fiscal year ending December 31, 1997, while the Company's midstream activities
accounted for the remainder.  The Company conducts its upstream operations in
each of its three core areas through wholly owned subsidiaries.  The California
Properties are operated by Stocker Resources Inc. ("Stocker"), the Sunniland
Trend properties are operated by Calumet Florida Inc. ("Calumet") and the
Illinois Basin Properties are operated by Plains Illinois Inc. ("Plains
Illinois").  The Company's midstream operations are conducted through various
wholly owned subsidiaries (referred to collectively as "Plains Marketing").
References to the Company in this Annual Report on Form 10-K (the "Report")
include Plains Resources Inc. and its subsidiaries, except as the context may
otherwise require./1/

          The Company's upstream business strategy is to increase its proved
reserves and cash flow by exploiting and producing crude oil and associated
natural gas from its existing properties, acquiring additional underdeveloped
crude oil properties and exploring for significant new sources of reserves.  The
Company concentrates its exploitation efforts on mature but underdeveloped crude
oil producing properties that meet the Company's targeted criteria.  Generally,
such properties were previously owned by major integrated or large independent
oil and natural gas companies, have produced significant volumes since initial
discovery and have significant estimated remaining reserves in place.
Management believes that it has developed a proven record in acquiring and
exploiting underdeveloped crude oil properties where it believes substantial
reserve additions and cash flow increases can be made through improved
production practices and recovery techniques and relatively low risk development
drilling.  An integral component of the Company's exploitation effort is to
increase unit operating margins, and therefore cash flow, by reducing unit
production expenses and increasing wellhead price realizations.  The Company
seeks to complement these exploitation efforts by pursuing certain higher risk
exploration opportunities which offer potentially higher rewards.  As part of
its business strategy, the Company periodically evaluates, and from time to time
has elected to sell, certain of its mature producing properties that it
considers to be nonstrategic or fully valued.  Such sales enable the Company to
focus on its core properties, maintain financial flexibility, control overhead
and redeploy the sales proceeds to activities that have potentially higher
financial returns.  The Company also seeks to capitalize on midstream
opportunities that exist as a result of inefficiencies within the crude oil
markets and the U.S. pipeline and transportation infrastructure.  On March 21,
1998, Plains All American Inc. ("Plains All American"), a wholly owned
subsidiary of the Company, entered into a definitive agreement to acquire 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 The Goodyear Tire & Rubber Company
("Goodyear").  Aggregate proceeds to Goodyear through closing are estimated at
$420 million.  The transaction is expected to be completed in 

------------
/(1)/ 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, "MBtus" 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 "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 the Company's
      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 reduced by estimated
      future operating expenses, development expenditures and abandonment costs
      (net of salvage value) associated therewith (before income taxes),
      calculated using product prices in effect on the date of determination,
      and "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.

                                       1
<PAGE>
 
the third quarter after regulatory approvals have been secured. See "Business--
All American Pipeline Acquisition". The Company's marketing of its own crude oil
production takes advantage of the marketing expertise attributable to its
midstream activities.

          During the five-year period ended December 31, 1997, the Company
incurred aggregate acquisition, exploitation, development, and exploration costs
of approximately $365.3 million, resulting in proved oil and natural gas reserve
additions (including revisions of estimates but excluding production) of
approximately 154.3 million BOE, or $2.37 per BOE, through implementation of its
business strategy.  See Item 2, "Properties--Oil and Natural Gas Reserves".
Approximately 94% of these expenditures were directed toward the acquisition,
exploitation and development of proved reserves while approximately 6% were
incurred on exploration activities.

          In order to manage its exposure to commodity price risk, the Company
routinely hedges a portion of its crude oil production.  For 1998, the Company
has entered into various fixed price and floating price collar arrangements.
Such arrangements generally provide the Company with downside price protection
on approximately 12,250 barrels of oil per day at a NYMEX crude oil spot price
("NYMEX Crude Oil Price") of approximately $19.80 per barrel.  Thus, based on
the Company's average fourth quarter 1997 crude oil production rate, these
arrangements generally provide the Company with downside price protection for
approximately 60% of its crude oil production.  In addition, the Company also
has fixed price  arrangements on 6,000 barrels per day in 1999 at a NYMEX Crude
Oil Price of $18.55 per barrel, or approximately 30% of fourth quarter 1997
crude oil production levels.  During the first quarter of 1998, the NYMEX Crude
Oil Price fluctuated significantly, closing as high as $17.82 per barrel and as
low as $13.21 per barrel.  At March 23, 1998, the NYMEX Crude Oil Price was
approximately $16.50 per barrel.

                                       2
<PAGE>
 
          The following table sets forth certain information with respect to the
Company's reserves over the last five years.  Such reserve volumes and values
were determined under the method prescribed by the Securities and Exchange
Commission (the "SEC"), which requires the application of year-end oil and
natural gas prices for each year, held constant throughout the projected reserve
life.  See Item 2, "Properties--Oil and Natural Gas Reserves" and Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations".

<TABLE>
<CAPTION>

                                                                   As of or for the Year Ended December 31,
                                          ----------------------------------------------------------------------------------
                                              1997                 1996              1995           1994             1993
                                          ------------        --------------     ------------    ------------     ----------
                                                       (in thousands, except ratios and per unit amounts)
<S>                                        <C>                  <C>               <C>             <C>               <C>
Present Value of Proved Reserves........   $510,993 (1)         $764,774 (1)      $366,780        $229,371          $134,539
Proved Reserves
  Crude oil and natural
   gas liquids (Bbls)...................    151,627              115,996            94,408          61,459            38,810
  Natural gas (Mcf).....................     60,350               37,273            43,110          51,009            49,397
  Oil equivalent (BOE)..................    161,685 (1)          122,208 (1)       101,593          69,960            47,043
Reserve Replacement Ratio(2)............        603%(3)              454%              647%(4)         619%              269%
Reserve Replacement Cost per BOE(5).....   $   2.71             $   1.76          $   2.14        $   1.49          $   5.39
Total upstream capital costs incurred...   $127,378             $ 51,255          $ 84,012        $ 40,849          $ 61,769
Percentage of total upstream capital
 costs attributable to:
  Acquisition...........................         34%                   7%               71%             48%               40%
  Development...........................         65%                  88%               27%             38%               43%
  Exploration...........................          1%                   5%                2%             14%               17%
Year-end NYMEX Crude Oil Price..........   $  18.34             $  25.92          $  19.55        $  17.76          $  14.17
</TABLE>
----------- 
(1) A large portion of the Company's reserve base (approximately 94% of 
    year-end 1997 reserve volumes) is comprised of long-life oil properties that
    are sensitive to crude oil price volatility. By comparison, calculating
    these amounts using the NYMEX Crude Oil Price in effect at December 31,
    1995, of $19.55 per barrel, results in a Present Value of Proved Reserves of
    $633 million and $452 million and estimated net proved reserves of 168
    million BOE and 112 million BOE at December 31, 1997 and 1996, respectively.
    See Item 7, "Management's Discussion and Analysis of Financial Condition and
    Results of Operations--Capital Resources, Liquidity and Financial 
    Condition--Changing Oil and Natural Gas Prices".
(2) 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 ("Reserve Additions"), by (b) each respective year's
    production.
(3) 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.
(4) Pro forma as if the acquisition of the Illinois Basin Properties occurred 
    on January 1, 1995. Such acquisition closed in December 1995 with an
    effective date of November 1, 1995. 
(5) Reserve Replacement Cost per BOE for a year is calculated by dividing
    upstream capital costs incurred for such year by such year's Reserve
    Additions.

ACQUISITION AND EXPLOITATION

  Acquisition and Exploitation Strategy

     The Company is continually engaged in the exploitation and development of
its existing property base and the evaluation and pursuit of additional
underdeveloped properties for acquisition.  The Company focuses on mature but
underdeveloped producing crude oil properties in areas where the Company
believes 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, the Company seeks to
increase production rates and improve a property's operating margin by reducing
unit production costs and enhancing the marketing arrangements of the oil
production.

     Once the Company identifies a prospective property for acquisition, it
conducts a technical review of existing production and operating practices in an
effort to identify any previously unrecognized 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

                                       3
<PAGE>
 
development opportunities.  A market study is also performed 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 the
Company's offer to purchase.

     The Company typically seeks to acquire a majority interest in the
properties it has identified and to act as operator of those properties.  The
Company has in the past and may in the future hedge a significant portion of the
acquired production, thereby partially mitigating product price volatility which
could have an adverse impact on exploitation opportunities.  If the Company is
successful in purchasing such properties, it then implements its 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, the Company may also seek
to increase its interest in the properties through acquisitions of offsetting
acreage, farmout drilling arrangements and the purchase of minority interests in
the properties.

     By implementing its exploitation plan, the Company seeks to increase
volumes and expand its reserve base.  The results of such activities are
reflected in additions and revisions to proved reserves.  During the five year
period ending December 31, 1997, net additions and revisions to proved reserves
totaled 73.5 million BOE or approximately 269% of cumulative net production for
such period.  Such reserves were added at an aggregate average cost of $2.92 per
BOE.  This activity excludes reserves added as a result of the Company's
acquisition activities.  Reserve additions related solely to the Company's
acquisition activities totaled 80.8 million BOE and were added at an aggregate
average cost of $1.86 per BOE.

     The Company's properties in its three core areas represent approximately
99% of total proved reserves at December 31, 1997.  Such properties were
previously owned and operated by major integrated oil and natural gas companies
and are comprised of underdeveloped crude oil properties believed by the Company
to have significant upside potential that can be evaluated through development
and exploitation activities.  During 1998, the Company estimates it will spend
approximately $91 million on the development and exploitation of its California,
Sunniland Trend and Illinois Basin Properties.  Set forth below is a discussion
of such properties.

  Current Exploitation Projects

     California Properties. Prior to its acquisition by the Company in May 1992,
Stocker was a sole purpose company formed in 1990 to acquire substantially all
of Chevron USA's ("Chevron") producing oil properties in the LA Basin.
Following the initial acquisition, the Company expanded its 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.  All
of the Company's properties in the LA Basin acquired prior to 1997 are
collectively referred to herein as the "LA Basin Properties". The LA Basin
Properties consist of long-life reserves discovered at various times between
1924 and 1966, and through December 31, 1997, the LA Basin Properties have
produced over 420 MMBbls of oil and 360 Bcf of natural gas. The Company has
performed various exploitation activities, including drilling additional wells,
returning previously marginal wells to economic production, optimizing
waterflood operations, improving artificial lift and facility equipment,
reducing unit production expenses and improving marketing margins. Through these
acquisition and exploitation activities, average daily production from this
area, net to the Company's interest, has increased from approximately 6,700 BOE
per day in 1992 to an average of 10,640 BOE per day during the fourth quarter of
1997.

     The Company has expended approximately $110.7 million in direct
acquisition, development and exploitation capital on the LA Basin Properties.
From the effective dates of acquisition through December 31, 1997, net
production from such properties totaled 18.2 million BOE, generating cumulative
net margin (oil and natural gas revenue less production expenses) and proceeds
from minor property sales of approximately $141.9 million.  Total estimated
proved reserves attributable to the LA Basin Properties have increased from 17.7
million BOE at initial acquisition to approximately 76.6 million BOE at December
31, 1997.  As a result, the Company's aggregate reserve addition cost to date
for the LA Basin Properties is approximately $1.17 per BOE.  During 1997, the
unit gross margin for this area averaged $8.83 per BOE.  Estimated future net
revenues and the Present Value of Proved Reserves at December 31, 1997, were
estimated at $649.4 million and $300.6 million, respectively.  The Company
estimates it will spend approximately $47 million during 1998 on the further
development and exploitation of the LA Basin Properties.

                                       4
<PAGE>
 
     During 1997, the Company expanded its operations in the LA Basin with the
acquisition of the Montebello Field (the "Montebello Acquisition"), and expanded
into another California area with the acquisition of the Arroyo Grande Field
(the "Arroyo Grande Acquisition").  Combined, these two fields added
approximately 43 million BOE to the Company's proved reserves at the acquisition
dates.

     In March 1997, the Company completed the acquisition of Chevron's interest
in the Montebello Field for approximately $25 million, effective February 1,
1997. The assets acquired consist of a 100% working interest and a 99.2% net
revenue interest in 55 producing oil wells and related facilities and also
includes approximately 450 acres of surface fee land.  The Montebello Field,
which is located approximately 15 miles from the Company's existing LA Basin
operations, has produced approximately 108 MMBbls of oil and 100 Bcf of natural
gas since its discovery in 1917.  At the acquisition date, the field was
producing approximately 800 barrels of oil and 800 Mcf of natural gas per day
and added approximately 23 MMBbls of oil equivalent to the Company's proved
reserves.

     In November 1997, the Company 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 10
MMBbls of crude oil or approximately 5% of the estimated original oil in place.
The assets acquired include surface and development rights to approximately
1,000 acres included in the 1,500 acre unit. The field is under continuous steam
injection and as of the acquisition date was producing approximately 1,600
barrels (approximately 1,500 barrels net to the Company's interest) of
approximately 14 degree API gravity oil per day from 70 wells and added
approximately 20 MMBbls to the Company's proved reserves. The aggregate
consideration for the Arroyo Grande Acquisition consisted of (i) rights to a 
non-producing property interest conveyed to Shell, (ii) the issuance of 46,600
shares of Series D Cumulative Convertible Preferred Stock (the "Series D
Preferred Stock") with an aggregate stated value of $23.3 million, and (iii) a
five-year warrant to purchase 150,000 shares of the Company's common stock
("Common Stock") at $25 per share. No proved reserves had been assigned to the
rights to the property interest conveyed.

     As with its other California properties, the Company intends to
aggressively exploit the properties acquired in 1997 to evaluate additional
reserve potential identified during its acquisition analyses.  In addition, the
Company's exploitation plans for these properties target improving the unit
gross margin by decreasing unit production expenses and increasing production
volumes through production enhancement activities similar to those employed in
its other California properties.  During 1998, the Company estimates that it
will spend approximately $17 million on the development and exploitation of the
Montebello and Arroyo Grande fields.

     Sunniland Trend Properties. During the first quarter of 1993, the Company
acquired all of the capital stock of Calumet for approximately $5 million.
Calumet was organized in February 1993 to purchase and operate a 50% working
interest in six producing fields in South Florida located in the Sunniland Trend
and previously owned and operated by Exxon Corporation ("Exxon"). During 1994,
Calumet acquired the remaining 50% working interest in the Sunniland Trend
Properties, increasing its working interest to approximately 100% and adding
approximately five million barrels of oil to its proved reserve base at the
acquisition date. The Company's aggregate interest in such properties is
referred to as the "Sunniland Trend Properties". The aggregate purchase price
for the additional 50% interest was approximately $13.6 million, including the
issuance of a five-year warrant valued at $2 million to purchase 750,000 shares
of Common Stock at an exercise price of $6.00 per share. The Sunniland Trend was
discovered by Exxon in 1943, and the properties have produced approximately 92
MMBls of oil through December 31, 1997. At the time of acquisition, production
from the properties was about 900 barrels of oil per day net to the Company. As
a result of development drilling on the property, the implementation of
exploitation activities designed primarily to repair failed wells and to
increase the fluid lift capacity of certain wells and the acquisition of the
remaining 50% working interest, the Company's net production increased to an
average of 5,430 barrels of oil per day during the fourth quarter of 1997.

     The Company has expended approximately $68.7 million in direct acquisition,
development and exploitation capital on the Sunniland Trend Properties.  From
the effective dates of acquisition through December 31, 1997, net production
from such properties totaled 6.3 MMBbl, generating cumulative net margin of
approximately $46.6 million.  Total estimated proved reserves attributable to
the Sunniland Trend Properties have increased from approximately 5.0 MMBbls at
initial acquisition to approximately 22.2 MMBbls at December 31, 1997.  As a
result, the Company's aggregate reserve addition cost to date for the Sunniland
Trend Properties is approximately $2.41 per BOE.  During 

                                       5
<PAGE>
 
1997, the unit gross margin for this area averaged $7.62 per BOE. At December
31, 1997, estimated future net revenues and the Present Value of Proved Reserves
were estimated at $86.8 million and $68.6 million, respectively. During 1998,
the Company estimates it will spend approximately $18 million on the further
development and exploitation of the Sunniland Trend Properties. In addition, the
Company intends to conduct exploration activities in this trend during 1998. See
"--Exploration--Current Exploration Projects--Sunniland Trend".

     Illinois Basin Properties.  In December 1995, the Company acquired all of
Marathon Oil Company's ("Marathon") producing and nonproducing upstream oil and
natural gas assets in the Illinois Basin (the "Illinois Basin Properties").
This acquisition was effective as of November 1, 1995.  At the acquisition date,
the Company added approximately 17.3 MMBls of oil to its proved reserve base.
The aggregate purchase price, including associated closing costs, was $51.5
million, comprised of 798,143 shares of Common Stock valued at $6.5 million and
$45.0 million cash. The majority of the cash portion was funded with the
proceeds of a $42 million bank facility.  The Illinois Basin Properties consist
of long-life oil reserves.  The largest field included in the Illinois Basin
Properties was discovered in 1905 and has produced over 410 MMBls of oil through
December 31, 1997.

     The Company has expended approximately $68.8 million in direct acquisition,
development and exploitation capital on the Illinois Basin Properties.  From the
effective date of acquisition through December 31, 1997, net production from
such properties totaled 2.8 MMBls, generating cumulative net margin of
approximately $28.2 million. The Company's 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 $8.56 per BOE during 1997.  As a result
of these operating expense reductions, reduced location price differentials and
higher average oil prices, this area's unit gross margin increased to $10.60 per
BOE during 1997 as compared to $5.37 per BOE at the time of acquisition.  Total
estimated proved reserves attributable to the Illinois Basin Properties have
increased from 17.3 MMBbls at initial acquisition to approximately 20.6 MMBbls
at December 31, 1997.  As a result, the Company's aggregate reserve addition
cost to date for the Illinois Basin Properties is approximately $2.94 per BOE.
Estimated future net revenues and the Present Value of Proved Reserves at
December 31, 1997, were estimated at $141.8 million and $73.2 million,
respectively.   The Company intends to aggressively exploit these properties to
evaluate additional reserve potential identified during its acquisition
analysis.  During 1998, the Company estimates it will spend approximately $9
million implementing its exploitation plan on the Illinois Basin Properties.
The primary focus of such development and exploitation program during 1998 will
be directed towards aggressively implementing projects to evaluate alternative
waterflood realignment patterns and injection methods.

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

     The Company believes that attractive acquisition opportunities which fit
the Company's criteria will continue to be available as a result of sales of
domestic oil properties by both major and independent oil companies.  While the
Company is continually evaluating acquisition opportunities, there can be no
assurance that any of these efforts will be successful.  The Company's 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.  Although the Company has
historically acquired producing properties located only in the continental
United States, it from time to time evaluates, and may in the future seek to
acquire, properties located outside the continental United States.

                                       6
<PAGE>
 
EXPLORATION

  Exploration Strategy
 
     The Company seeks to complement its strategy of acquiring and exploiting
mature but underdeveloped crude oil properties by dedicating a substantially
smaller portion of its annual capital expenditures to higher risk but
potentially higher reward exploration opportunities.  The Company focuses on
exploration opportunities that, if successful, could have a substantial positive
impact on production, cash flow and ultimately proved reserves.  However, there
can be no assurance that any of its exploration projects will be successful.

     In 1996, the Company and 3DX Technologies Inc. ("3DX") formed a joint
venture to pursue the Company's existing exploration projects and a five-year
strategic alliance to jointly pursue new exploration and exploitation
opportunities that are candidates for the application of 3-D seismic technology.
The joint venture covers exploration activities in the Sunniland Trend and the
Gulf Coast areas of Texas and Louisiana.  3DX bears principal responsibility
for the geological and geophysical oversight and project technical management of
such projects.  In connection with the joint venture, 3DX acquired 8% to 20% of
the Company's working interests in certain projects.  3DX will have certain
rights to participate for up to 20% in the Company's new exploration and
exploitation projects in these areas.

  Current Exploration Projects

     Sunniland Trend.  The focus of the Company's exploration effort in the
Sunniland Trend is to identify and evaluate prospects that are analogous to the
existing producing fields in this trend.  Although this trend was discovered in
1943, the Company and its partners are attempting to integrate historical
exploration methods with recent advancements in seismic technology to evaluate
the exploration potential of the Sunniland Trend.

     In February 1998, the Company and Collier Resources Company ("Collier")
executed an exploration agreement (the "Exploration Agreement") covering
approximately 800,000 mineral acres which are located onshore South Florida in
Collier, Lee and Hendry Counties.  Approximately 50% of such acreage is located
under federally-owned surface land.  Terms of the Exploration Agreement provide
for a minimum term of two years with extensions at the Company's option for up
to eight years.  Work commitments of the Exploration Agreement provide for the
Company to spend up to $20 million on exploration activities involving Collier's
mineral holdings over the next several years.  Such activities include acquiring
a specified amount of 2-D and 3-D seismic data across leads and prospects and
drilling a minimum number of wells.

     Portions of the acreage will be subject to existing joint ventures and
alliances with certain industry participants, including 3DX, which will perform
the geophysical and geological analyses with regard to the Exploration
Agreement.  Prior to the signing of the Exploration Agreement, the Company held
leasehold interests in approximately 132,000 gross acres.

     Preliminary plans for 1998 include gathering 2-D and/or 3-D seismic data
over various prospects and leads and drilling one exploratory well in a new
prospect.

     General.  During 1998, the Company estimates it will spend approximately $6
million on exploration activities, principally in the Sunniland Trend.  While
all drilling activities are subject to numerous risks, the risks associated with
exploration activities are significantly greater than those associated with the
Company's other exploitation and development activities.  There can be no
assurance that any of the Company's current exploration or higher risk
exploitation projects will result in the discovery of proved reserves or the
establishment of commercially viable oil or natural gas production.

     The Company has historically conducted a portion of its exploration
activities with outside partners.  When deemed appropriate, the Company will
continue to solicit industry and financial partners to participate in
exploration projects on negotiated terms.  The level of the Company's capital
expenditures for these projects, and its working and revenue interests, will
vary depending on the amount and terms of such outside participation.

                                       7
<PAGE>
 
DISPOSITION OF PROPERTIES

     The Company periodically evaluates, and from time to time has elected to
sell, certain of its mature producing properties that it considers to be
nonstrategic or fully valued.  Such sales enable the Company to focus on its
core properties, maintain financial flexibility, reduce overhead and redeploy
the proceeds therefrom to activities that the Company believes potentially have
a higher financial return.  During 1997, 1996 and 1995, the Company sold
nonstrategic oil and natural gas properties located primarily in the Gulf Coast
areas of Texas and Louisiana and in Utah for proceeds of $2.7 million, $3.1
million and $7.4 million, respectively.  As a result, approximately 99% of the
Company's 1997 year-end proved reserve volumes and proved reserve value were
associated with its properties in California, the Sunniland Trend and the
Illinois Basin.

MIDSTREAM ACTIVITIES

     The Company's midstream activities include two distinguishable but
interrelated business activities.  Such activities are (i) crude oil gathering
and marketing and (ii) crude oil terminalling, storage, blending and exchange.
The Company's midstream activities have expanded significantly, with midstream
gross margin (revenues less direct expenses of purchases, transportation,
storage and terminalling) having increased approximately 635% from $1.7 million
in 1992 to $12.5 million in 1997.

     The crude oil distribution chain extends from the wellhead, where crude oil
moves by truck and gathering systems to terminal and pipeline injection stations
and major pipelines, to major crude oil trading locations for ultimate
consumption by refineries and other end markets (the "Distribution Chain").  The
Company's gathering and marketing operations include the purchase of crude oil
at the wellhead and the bulk purchase of crude oil at pipeline and terminal
facilities for aggregation and subsequent resale at various points along the
crude oil Distribution Chain.  In most cases, the Company performs a merchant
function generating profit margins by buying crude oil at competitive prices,
efficiently transporting or exchanging the crude oil along the Distribution
Chain and marketing the crude oil to refineries or other customers at favorable
prices.  The Company aggregates purchased volumes with its own production at
major crude oil interchanges and trading locations, which enables it to obtain
higher prices for its own production while realizing profits on the production
purchased from others.  Except for crude oil purchased from time to time as
inventory to service the needs of its terminalling and storage customers, the
Company's policy is to purchase only crude oil for which it has a market and to
structure its sales contracts so that crude oil price fluctuations do not
materially affect the gross margin which it receives.  The crude oil marketing
business is characterized by a large volume of transactions with low margins.
The Company has generally maintained a gross margin of approximately 2% in its
marketing activities for each of the years 1993 through 1997.  The Company also
routinely analyzes opportunities for possible purchase or construction of
gathering and pipeline systems, processing and storage facilities and various
other related capital investment projects to enhance its profitability in the
markets in which it operates.

     The Company owns and operates a two million barrel, above-ground crude oil
storage and terminalling facility in Cushing, Oklahoma (the "Cushing Terminal").
The Company utilizes the Cushing Terminal to provide storage and terminalling
services for its own account and for third parties on a negotiated basis and to
serve as an aggregation, terminalling and distribution point for establishing
and maintaining markets for up to 24 different varieties of foreign and domestic
crude oils. The Company estimates that approximately 60% to 70% of the tankage
capacity available at the Cushing Terminal was used in 1997; accordingly,
substantial additional capacity is available without the expenditure of
additional capital. The Company recently received regulatory approval to
construct an additional one million barrels of tank capacity at the Cushing
Terminal and is formulating its plans with respect thereto. Because of its
initial investment in land, engineering and environmental studies, pipeline
interconnects and the manifold and pumping system, the cost to construct
incremental storage capacity is estimated at $10.00 per barrel of shell
capacity. In addition, the Company owns a 360,000 barrel terminal and dock
facility located in Ingleside, Texas, just north of the Port of Corpus Christi
(the "Ingleside Terminal"). Approximately 60% of the Ingleside Terminal's
storage capacity is committed to a lease agreement with five years remaining on
the term and the remaining 40% is used to support the Company's crude oil
purchasing activities. The Company acquired the Ingleside Terminal in early
1996.

                                       8
<PAGE>
 
     The Cushing Terminal was completed in December 1993.  The facility was
designed to accommodate the numerous grades of crude oil used by refiners and
consists of two million barrels (fourteen 100,000 barrel tanks and four 150,000
barrel tanks) of above-ground shell storage capacity.  The Company's total
capital investment in the Cushing Terminal through December 31, 1997, was
approximately $31.1 million, which includes the cost of land acquisition,
engineering and environmental studies, construction-phase interest, pipeline
interconnects and an oversized manifold and pumping system that was designed and
constructed to accommodate expansion up to an aggregate ten million barrels of
storage capacity.  The Company estimates that its storage tanks have a useful
life in excess of 60 years.  The facility is connected to major pipelines into
and out of the Cushing interchange and can operate at a daily throughput rate of
approximately 800,000 Bbls.

     Cushing is the largest wet barrel trading hub in the United States 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.
The Cushing Terminal was constructed primarily to capitalize on the crude oil
supply and demand imbalance in the Midwest caused by the continued decline of
traditional regional supplies, increasing imports and an inadequate pipeline and
terminal infrastructure.  Based upon the Company's analysis of existing storage
facilities at Cushing and the anticipated increase in crude oil volumes to be
transported through Cushing, the Company believes that there will be an
increasing demand for additional storage capacity at Cushing; however, there can
be no assurance that such demand will increase.  The Company generates revenue
from the Cushing Terminal through a combination of storage, reservation and
throughput fees from (i) refiners and gatherers seeking to segregate or custom
blend crudes for refining feedstocks, (ii) pipelines, refiners and traders
requiring segregated tankage for foreign cargoes, (iii) traders who make or take
delivery under the NYMEX contract, and (iv) producers seeking to increase their
marketing alternatives and arbitrage opportunities entered into for the
Company's own account in contango market crude oil trading activities.  The
storage and terminal business is generally counter-cyclical to the marketing
business insofar as the demand for storage opportunities is higher and the
Company's ability to capture profits from arbitrage opportunities existing in
the market is enhanced in a contango market as opposed to a market in
backwardation.  Conversely, marketing margins are typically stronger in a
backward market.  A contango crude oil futures market exists when the futures
price of a subsequent month exceeds the price of a prior month, whereas a market
is in backwardization when the opposite condition exists.  Such market allows
the Company to simultaneously purchase and sell crude oil and lock-in a profit.
Because of its designation as an official NYMEX delivery point and its physical
capacity to receive, store and redeliver crude oil, the Cushing Terminal
provides the optimal mechanism to capitalize on a contango market.

ALL AMERICAN PIPELINE ACQUISITION

     On March 21, 1998, Plains All American, a wholly owned subsidiary of the
Company, entered into a definitive agreement to acquire all of the outstanding
capital stock of the Celeron Companies from Goodyear.  Aggregate proceeds to
Goodyear through closing are estimated at $420 million.  The principal assets of
the entities to be acquired include the All American Pipeline System, a 1,233-
mile crude oil pipeline extending from California to Texas, and a 45-mile crude
oil gathering system in the San Joaquin Valley of California, as well as other
assets related to such operations.  The purchase price is subject to certain
adjustments through the closing date, and the transaction is subject to
regulatory review and approval by the United States Department of Justice and
the Federal Trade Commission under the Hart-Scott-Rodino Anti-Trust Improvements
Act of 1976, as amended, and by the Public Utilities Commission of the State of
California.  The transaction  is expected to be completed in the third quarter
of 1998 after regulatory approvals have been secured.

     A major portion of the financing for the transaction will be provided
through a $325 million, limited recourse bank facility made available to Plains
All American by ING Barings and BankBoston.  In addition to the bank facility,
the Company will make a capital contribution to Plains All American of up to
$130 million, which will be used to fund the balance of the purchase price and
transaction costs and provide initial working capital.  To finance its capital
contribution, the Company will borrow approximately $50 million under its
existing revolving bank facility and has entered into financing commitments for
a new issue of privately placed, convertible preferred stock aggregating
approximately $80 million. Commitments for the preferred stock placement have
been obtained from a group of equity investors comprised primarily of existing
shareholders.  The preferred stock has an aggregate stated value of $80 million
and bears a cumulative dividend of 9.5% per annum, payable semi-annually in
either cash or additional shares of 

                                       9
<PAGE>
 
preferred stock at the Company's option. Each share of preferred stock is
convertible into 27.78 shares of Common Stock (an effective conversion price of
$18.00 per share) and in certain circumstances may be converted at the Company's
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. The preferred stock is
redeemable at the option of the Company at 110% of stated value after March 31,
1999, and at declining amounts thereafter. If not previously redeemed or
converted, the preferred stock is required to be redeemed in 2012.

     The All American Pipeline is the single largest crude oil pipeline
connecting California to West Texas, where it connects with pipelines that
transport crude oil to Cushing, Oklahoma and the Gulf Coast.  The 45-mile
gathering system is located in the San Joaquin Valley, currently the most
prolific crude oil producing region in the continental United States.  The areas
serviced by the pipeline and gathering system currently produce over 700,000
barrels of crude oil per day, representing approximately 15% of total oil
production in the continental United States.  For 1997, the operations to be
acquired generated approximately $65 million in EBITDA.

OPERATING ACTIVITIES

     The following table presents certain information with respect to the
Company's upstream oil and natural gas producing activities and its midstream
marketing, transportation, terminalling and storage activities during the three
years ended December 31, 1997, 1996 and 1995:


<TABLE>
<CAPTION>
                                                                Year Ended December 31,
                                                          ----------------------------------
                                                             1997         1996        1995
                                                          ---------     --------    --------
                                                                     (in thousands)
<S>                                                        <C>          <C>         <C> 
Sales to unaffiliated customers:
   Oil and natural gas..................................   $109,403     $ 97,601    $ 64,080
   Marketing, transportation and storage................    752,522      531,698     339,826
Operating profits:                                      
   Oil and natural gas (1)..............................   $ 64,098     $ 59,085    $ 34,029
   Marketing, transportation and storage (2)............     12,618        9,621       6,480
Identifiable assets:                                    
   Oil and natural gas..................................   $408,503     $309,107    $271,248
   Marketing, transportation and storage................    148,316      121,142      80,798
</TABLE> 
------------
(1) Consists primarily of oil and natural gas sales less production expenses.
 
(2) Consists primarily of marketing, transportation and storage sales less
    purchases, transportation and storage expenses.  Includes approximately
    $2.5 million of operating profit attributable to contango market
    transactions in 1997.

     Operating profits as a percentage of sales are significantly lower for the
Company's marketing, transportation and storage activities than for its oil and
natural gas producing activities because the cost of crude oil purchased for
resale is higher, as a percentage of sales price, than the Company's cost to
produce oil and natural gas. See "--Midstream Activities".

GENERAL

     The Company was incorporated under the laws of the State of Delaware in
1976.  The Company's executive offices are located at 500 Dallas, Suite 700,
Houston, Texas 77002, and its telephone number is (713) 654-1414.  Prior to
March 30, 1998, the Company's executive offices were located at 1600 Smith
Street, Suite 1500, Houston, Texas 77002.

PRODUCT MARKETS AND MAJOR CUSTOMERS

     The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and natural gas.  Historically, the
markets for oil and natural gas have been volatile and are likely to continue to
be volatile in the future.  The prices received by the Company for its oil and
natural gas production and the levels of such production are subject to wide
fluctuations and depend on numerous factors beyond the Company's control,
including 

                                       10
<PAGE>
 
seasonality, the condition of the United States economy (particularly the
manufacturing sector), foreign imports, political conditions in other 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 oil and natural gas have had, and could
have in the future, an adverse effect on the carrying value of the Company's
proved reserves and the Company's revenues, profitability and cash flow. A large
portion of the Company's reserve base (approximately 94% of year-end 1997
reserve volumes) is comprised of long-life oil properties that are sensitive to
crude oil price volatility. The crude oil price received by the Company at
December 31, 1997, upon which proved reserve volumes, the Present Value of
Proved Reserves and the Standardized Measure as of such date were based, was
$18.34 per barrel. During the first quarter of 1998, the NYMEX Crude Oil Price
fluctuated significantly, closing as high as $17.82 per barrel and as low as
$13.21 per barrel. At March 23, 1998, the NYMEX Crude Oil Price was
approximately $16.50 per barrel. See Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Capital Resources,
Liquidity and Financial Condition--Changing Oil and Natural Gas Prices".

     In order to manage its exposure to price risks in the marketing of its oil
and natural gas, the Company from time to time enters into fixed price delivery
contracts, floating price collar arrangements, financial swaps and oil and
natural gas futures contracts as hedging devices.  To ensure a fixed price for
future production, the Company may sell a futures contract and thereafter either
(i) make physical delivery of its product to comply with such contract or (ii)
buy a matching futures contract to unwind its futures position and sell its
production to a customer.  These same techniques are also utilized to manage
price risk for certain production purchased from customers of Plains Marketing.
Such contracts may expose the Company to the risk of financial loss in certain
circumstances, including instances where production is less than expected, the
Company's customers fail to purchase or deliver the contracted quantities of oil
or natural gas, or a sudden, unexpected event materially impacts oil or natural
gas prices.  Such contracts may also restrict the ability of the Company to
benefit from unexpected increases in oil and natural gas prices.  See Item 2,
"Properties--Oil and Natural Gas Reserves".

     Substantially all of the Company's California crude oil and natural gas
production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could result in the Company having to find
transportation alternatives, increased transportation costs to the Company or
involuntary curtailment of a significant portion of its crude oil and natural
gas production.

     Certain of the Company's 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 the Company's natural gas, may in the future adversely affect the
Company's ability to sell its natural gas production.

     All of the Company's natural gas production in California is produced as a
by-product of the Company's crude oil production.  As a result of high inert
content, the Company's gas production in the Montebello Field is difficult to
market and currently is delivered for no value.  To ensure that the Company is
able to develop and produce its oil reserves without restriction due to lack of
markets, the Company has made arrangements with the former owner of the
Montebello Field to take its natural gas production volumes at no incremental
value when the Company is unable to find a market for the gas. The Company
intends to spend approximately $2.5 million during 1998 and 1999 to improve the
quality of the gas through upgrading and refining the existing gas collection
system, as well as adding additional processing capacity. The Company believes
that this will enable it to obtain an alternate market for the gas production,
although such market cannot be assured.

     Before 1985, substantially all of the Company's natural gas production was
sold directly to pipeline companies which were responsible for resale and
transportation of the natural gas to end-users.  Since that time, however, with
the adoption of various orders by the Federal Energy Regulatory Commission
("FERC") (see "--Regulation--Transportation and Sale of Natural Gas") and the
deregulation of natural gas pursuant to the Natural Gas Policy Act of 1978
("NGPA") and the Natural Gas Wellhead Decontrol Act of 1989 (the "Decontrol
Act"), the FERC has actively promoted competition in the nationwide market for
natural gas and has encouraged pipelines to significantly reduce their role as
merchants of natural gas and to make transportation services available on an
"open-access", nondiscriminatory basis.  

                                       11
<PAGE>
 
Since these regulatory initiatives were begun, natural gas producers such as the
Company have been able to sell their natural gas supplies directly to utilities
and other end-users.

     In addition to the regulatory changes discussed above, deregulation of
natural gas prices under the NGPA and the Decontrol Act has increased
competition and volatility of natural gas prices.  Since demand for natural gas
is generally highest during winter months, prices received for the Company's
natural gas are subject to seasonal variations and other fluctuations.  All of
the Company's natural gas production is currently sold under various
arrangements at spot indexed prices.  In certain instances, the Company enters
into financial arrangements to hedge its exposure to spot price fluctuations.
See Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Capital Resources, Liquidity and Financial Condition--
Changing Oil and Natural Gas Prices" and Item 2, "Properties--Production and
Sales".

     Sales to Koch Oil Company ("Koch") and Sempra Energy Trading Corporation
(formerly AIG Trading Corporation) accounted for 27% and 11%, respectively, of
the Company's total revenue (exclusive of interest and other income) during
1997.  Customers accounting for more than 10% of total revenue for 1996 and 1995
were as follows:  1996 -- Koch - 16% and Basis Petroleum, Inc. ("Basis",
formerly Phibro Energy USA, Inc.) - 11%; 1995 -- Phibro Inc. ("Phibro") - 16%
and Basis - 12%.  No other single customer accounted for as much as 10% of total
sales during 1997, 1996 or 1995.  Additionally during 1997, Unocal Energy
Trading Inc. ("Unocal"), Marathon Oil Company and Exxon accounted for
approximately 52%, 23% and 10%, respectively, of the Company's oil and gas
sales.  During 1997, Unocal and Marathon Oil Company purchased the crude oil
from the LA Basin Properties and the Illinois Basin Properties, respectively.
See Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations".

COMPETITION

  Oil and Natural Gas Producing Activities

     The Company's 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 the Company's larger competitors
possess and employ financial and personnel resources substantially greater than
those available to the Company.  Such companies are able to pay more for
productive oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than the Company's financial or human resources permit.  The Company's
ability to acquire additional properties and to discover reserves in the future
will be dependent upon its 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

     The Company faces intense competition in purchasing and marketing crude oil
and in the crude oil storage business.  Its competitors include 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 the Company's and control substantially greater supplies of crude oil.
Although the Company believes that the environmental safeguards and operating
capabilities of the Cushing Terminal are superior to other existing facilities
in Cushing, the Company competes with larger companies that possess superior
financial resources and have an established business presence.  Such advantages
could inhibit the development of the Company's business for the Cushing
Terminal.

REGULATION

     The Company's operations are subject to extensive and continually changing
regulation, as legislation affecting the oil and natural gas industry is under
constant review for amendment and expansion.  Many departments and agencies,
both federal and state, are authorized by statute to issue and have issued rules
and regulations binding on the oil and natural gas industry and its individual
participants.  The failure to comply with such rules and 

                                       12
<PAGE>
 
regulations can result in substantial penalties. The regulatory burden on the
oil and natural gas industry increases the Company's cost of doing business and,
consequently, affects its profitability. However, the Company does not believe
that it is affected in a significantly different manner by these regulations
than are its competitors in the oil and natural gas industry. Due to the myriad
and complex federal and state statutes and regulations which may affect the
Company, directly or indirectly, the following discussion of certain statutes
and regulations should not be relied upon as an exhaustive review of all
regulatory considerations affecting the Company's operations.

  OSHA

     The Company is also subject to the requirements of the Federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes.  The Company
believes that its operations are in substantial compliance with OSHA
requirements, including general industry standards, record keeping requirements
and monitoring of occupational exposure to regulated substances.

  Commodities Regulation

     The Company's hedging activities operations are subject to constraints
imposed under the Commodity Exchange Act and the rules of the NYMEX.  The
futures and options contracts that are traded on the NYMEX are subject to strict
regulation by the Commodity Futures Trading Commission.

  Trucking Regulation

     The Company operates a fleet of trucks to transport crude oil as a private
carrier.  As a private carrier, the Company is subject to certain motor carrier
safety regulations issued by the Department of Transportation ("DOT").  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.  The Company is also
subject to OSHA with respect to its trucking operations.

  Pipeline Regulation

     The Company's crude oil pipelines and natural gas gathering pipelines are
subject to construction, installation, operating and safety regulation by the
DOT and various other federal, state and local agencies.  The Pipeline Safety
Act of 1992, among other things, amends the Hazardous Liquid Pipeline Safety Act
of 1979 ("HLPSA") in several important respects.  It requires the Research and
Special Programs Administration ("RSPA") of DOT to consider environmental
impacts, as well as its traditional public safety mandate, when developing
pipeline safety regulations.  In addition, the Pipeline Safety Act mandates the
establishment by DOT of pipeline operator qualification rules requiring minimum
training requirements for operators, and requires that pipeline operators
provide maps and records to RSPA.  It also authorizes RSPA to require that
pipelines be modified to accommodate internal inspection devices, to mandate the
installation of emergency flow restricting devices for pipelines in populated or
sensitive areas, and to order other changes to the operation and maintenance of
petroleum and natural gas pipelines.  Significant expenses could be incurred in
the future if additional safety measures are required or if safety standards are
raised and exceed the current pipeline control system capabilities.

     States are largely preempted from regulating pipeline safety by federal law
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.  The
Company does not anticipate any significant problems in complying with
applicable state laws and regulations in those states in which it operates.

  Transportation and Sale of Crude Oil

     Sales of crude oil and condensate can be made by the Company at market
prices not subject at this time to price controls.  However, the price that the
Company receives from the sale of these products is affected by the cost of
transporting the products to market.  Commencing in October 1993, the FERC
issued a series of orders (Order No. 561 and 561-A) in which it revised its
regulations governing the rates that may be charged by oil pipelines.  The new
rules, 

                                       13
<PAGE>
 
which became effective January 1, 1995, provide a simplified, generally
applicable method for regulating such rates by use of an index for setting rate
ceilings.  In certain circumstances, the new rules permit oil pipelines to
establish rates using traditional cost of service and other methods of
ratemaking.  These rules could increase the cost of transporting crude oil and
condensate by pipeline.  On October 28, 1994, the FERC issued two separate
Orders (No. 571 and 572), which adopt additional regulations governing rates
that an oil pipeline may be authorized to charge.  Order No. 571 authorizes a
pipeline to implement cost-of-service based rates, provided it can demonstrate
that there is a substantial divergence between the actual costs experienced by
the carrier and the indexed rate that the pipeline is directed to charge under
Order No. 561.  In Order No. 572, the FERC adopted regulations that authorize a
pipeline to charge market-based rates, provided it can demonstrate that it lacks
significant market power in the market(s) in which it proposes to charge such
rates.  These rules have been affirmed by the reviewing courts.

  Transportation and Sale of Natural Gas

     Prior to January 1, 1993, various aspects of the Company's natural gas
operations were subject to regulation by the FERC under the Natural Gas Act of
1938 (the "NGA") and the NGPA with respect to "first sales" of natural gas,
including price controls and certificate and abandonment authority regulations.
However, as a result of the enactment of the Decontrol Act, the remaining "first
sales" restrictions imposed by the NGA and the NGPA terminated on January 1,
1993.

     The FERC regulates interstate natural gas pipeline transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas.  Since the latter part of 1985, the FERC has adopted policies
intended to make natural gas transportation more accessible to natural gas
buyers and sellers on an open and non-discriminatory basis.  The FERC's most
recent action in this area, Order No. 636, reflected the FERC's finding that,
under the then-existing regulatory structure, interstate pipelines and other
natural gas merchants, including producers, did not compete on a "level playing
field" in selling natural gas.  Order No. 636 instituted individual pipeline
service restructuring proceedings, designed specifically to "unbundle" those
services (e.g., transportation, sales and storage) provided by many interstate
pipelines so that buyers of natural gas may secure natural gas supplies and
delivery services from the most economical source, whether interstate pipelines
or other parties.  The FERC has issued final orders in all of the restructuring
proceedings and has announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price which shippers can charge for their released capacity.  The FERC has
also adopted a new policy regarding the use of non-traditional methods of
setting rates for interstate natural gas pipelines in certain circumstances as
alternatives to cost of service based rates.  A number of pipelines have
obtained FERC authorization to charge negotiated rates as one such alternative.
The Company cannot predict what action the FERC will take in the reexamination
of its transportation-related policies, nor can it accurately predict whether
the FERC's actions will achieve its stated goal of increasing competition in
domestic natural gas markets.  However, the Company does not believe that it
will be treated materially differently than other natural gas producers and
marketers with which it competes.

     Although the FERC's actions, such as Order No. 636, do not regulate natural
gas producers such as the Company, these 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 the Company's
business or operations.  On a prospective basis, however, such orders may
substantially increase the burden on the producers and transporters to
nominate and deliver on a daily basis a specified volume of natural gas.
Producers and transporters which deliver deficient volumes or volumes in excess
of such daily nominations could be subject to additional charges by the pipeline
carriers.

     The United States Court of Appeals for the District of Columbia Circuit has
affirmed the FERC's Order No. 636 restructuring rule and remanded certain issues
for further explanation or clarification.  Numerous petitions seeking judicial
review of the individual pipeline restructuring orders are currently pending in
that Court.  Although it is difficult to predict when all appeals of pipeline
restructuring orders will be completed or their impact on the Company, the
Company does not believe that it will be affected by the restructuring rule and
orders any differently than other natural gas producers and marketers with which
it competes.

                                       14
<PAGE>
 
     Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts.  The Company cannot predict when or if any
such proposals might become effective or their effect, if any, on the Company's
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 the Company's cost of doing business and, consequently, affects its
profitability and cash flow.  Inasmuch as laws and regulations are frequently
expanded, amended or reinterpreted, the Company is unable to predict the future
cost or impact of complying with such regulations.

  Regulation of Production

     The production of 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 the
Company owns and operates 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 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 the Company can produce from its wells and to limit the number of
wells or the locations at which the Company 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.

  Environmental Regulation

     General.  Various 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 the Company's operations and costs.  In
particular, the Company's exploration, exploitation and production operations,
its activities in connection with storage and transportation of crude oil and
other liquid hydrocarbons and its use of facilities for treating, processing or
otherwise handling hydrocarbons and wastes therefrom are subject to stringent
environmental regulation.  As with the industry generally, compliance with
existing and anticipated regulations increases the Company's overall cost of
business.  Such areas affected include unit production expenses primarily
related to the control and limitation of air emissions and the disposal of
produced water, capital costs to drill exploration and development wells due to
solids control and capital costs to construct, maintain and upgrade equipment
and facilities.  While these regulations affect the Company's capital
expenditures and earnings, the Company believes that such regulations do not
affect its competitive position in that the operations of its competitors that
comply with such regulations are similarly affected.  Environmental regulations
have historically been subject to frequent change by regulatory authorities, and
the Company is unable to predict the ongoing cost to it of complying with these
laws and regulations or the future impact of such regulations on its operation.
A discharge of hydrocarbons or hazardous substances into the environment could,
to the extent such event is not insured, subject the Company to substantial
expense, including both the cost to comply with applicable regulations and
claims by neighboring landowners and other third parties for personal injury and
property damage.

     A significant portion of the Miami Fee acreage in Cameron Parish,
Louisiana, is within the Sabine National Wildlife Refuge (the "Refuge"), and
operations therein are subject to the National Wildlife Refuge Administration
Act and the regulations promulgated thereunder (the "Wildlife Refuge Act").  The
Wildlife Refuge Act states that no person may use, occupy, conduct any activity
on or remove property from any area located within a wildlife refuge unless a
permit has been granted for such use, occupation, conduct, activity or removal
of property. The Company has plugged and abandoned the wells drilled on its
Miami Fee acreage in prior years and is currently completing the requirements
established by the Regional Director of the Refuge.

     Although the Company obtained environmental studies on its properties in
California, the Sunniland Trend and the Illinois Basin, and the Company believes
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, the Company
negotiated an agreement with Chevron, a prior owner of the 

                                       15
<PAGE>
 
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 the
Company agreed to excavate and remediate nonhazardous crude oil contaminated
soils. The Company is obligated to construct and operate (for the next 13 years)
a minimum of five acres of bioremediation cells for crude oil contaminated soils
designated for excavation and treatment by Chevron. While the Company believes
that it does not have any material obligations for operations conducted prior to
Stocker's acquisition of the properties from Chevron, other than its 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 it 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 the Sunniland Trend Properties is located within the Big
Cypress National Preserve and the Company's 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 the Company's 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 which require the use of additional land for drilling
operations.  The Master Plan of Operations also requires that the Company
restore the surface property affected by its drilling and production operations
upon cessation of these activities.  The Company does not anticipate that
expenditures required to comply with such regulations will have a material
adverse effect on its current operations.

     Approximately 183 acres of the 450 acres acquired in the Montebello
Acquisition 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.
While 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 the Company's operations and its planned
activities or future commercial and/or residential development, the Company
believes that it will be able to operate the existing wells and realize the
reserve potential identified in its acquisition analysis without undue
restrictions or prohibitions.

     Water.  The Oil Pollution Act ("OPA") was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972 ("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 removal costs 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 United States.  In the event of an oil spill into such
waters, substantial liabilities could be imposed upon the Company.  States in
which the Company operates have also enacted similar laws.  Regulations are
currently being developed under OPA and state laws that may also impose
additional regulatory burdens on the Company.

     The FWPCA imposes restrictions and strict controls regarding the discharge
of produced waters and other oil and natural gas wastes into navigable waters.
Permits must be obtained to discharge pollutants to state and federal waters.
The FWPCA provides for civil, criminal and administrative penalties for any
unauthorized discharges of oil and other hazardous substances in reportable
quantities and, along with the OPA, imposes substantial potential liability for
the costs of removal, remediation and damages.  State laws for the control of
water pollution also provide varying civil, criminal and administrative
penalties and liabilities in the case of a discharge of petroleum or its
derivatives into state waters.  The EPA has promulgated regulations that require
many oil and natural gas production operations to obtain permits to discharge
storm water runoff.  At some facilities, such as the Sunniland Trend Properties,
the Company eliminated this permit requirement by collecting all potentially
contaminated storm water and disposing of it through the Company's underground
injection control ("UIC") disposal wells.  At other facilities, the Company has
applied for 

                                       16
<PAGE>
 
and obtained any necessary storm water discharge permits, and is currently in
substantial compliance with applicable permit conditions. The Company believes
that compliance with existing permits and compliance with foreseeable new permit
requirements will not have a material adverse effect on the Company's financial
condition or results of operations.

     Air Emissions.  The operations of the Company are subject to the Federal
Clean Air Act and comparable state and local statutes.  The Company believes
that its operations are in substantial compliance with such statutes in all
states in which they operate.

     Amendments to the Federal Clean Air Act enacted in late 1990 (the "1990
Federal Clean Air Act Amendments") require or will require most industrial
operations in the United States to incur capital expenditures in order to meet
air emission control standards developed by the Environmental Protection Agency
(the "EPA") and state environmental agencies.  In particular, the Company's LA
Basin properties are located in an "extreme" non-attainment area for ozone.
This classification will force the local air quality regulatory authority, the
South Coast Air Quality Management District, to adopt stringent controls on all
emissions of nitrogen oxide and volatile organic compounds.  As a result of
these future regulations, the Company may incur future capital expenditures to
reduce air emissions from the LA Basin production facilities.  In addition, the
1990 Federal Clean Air Act Amendments include a new operating permit for major
sources ("Title V permits"), and several of the Company's facilities may require
permits under this new program.  Although no assurances can be given, the
Company believes implementation of the 1990 Federal Clean Air Act Amendments
will not have a material adverse effect on the Company's financial condition or
results of operations.

     Solid Waste.  The Company generates non-hazardous solid 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.  RCRA also governs the
disposal of hazardous wastes.  At present, the Company is not required to comply
with a substantial portion of the RCRA requirements because the Company's
operations generate minimal quantities of hazardous wastes.  However, it is
anticipated that additional wastes, which could include wastes currently
generated 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 may
result in additional capital expenditures or operating expenses by the Company.

     Superfund.  The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as "Superfund", imposes 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 and
companies that disposed or arranged for the disposal of the hazardous substances
found at the site.  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. In the course of its ordinary operations, the Company may generate waste
that may fall within CERCLA's definition of a "hazardous substance". The Company
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
or released into the environment.

     The Company currently owns or leases, and has in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of oil and natural gas.  Although the Company has 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 the Company or on or under other locations
where such 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 the Company's control.
These properties and wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws.  Under such laws, the Company 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.

                                       17
<PAGE>
 
FEDERAL TAXATION

     At December 31, 1997, the Company and its subsidiaries, which together file
a consolidated federal income tax return, had federal income tax net operating
loss ("NOL") carryforwards of approximately $172 million.  Of that amount,
approximately $12 million is subject to separate return limitation year
restrictions and may only be utilized to the extent certain subsidiaries which
generated the NOL's have taxable income.  At December 31, 1997, the Company had
approximately $159 million of alternative minimum tax ("AMT") net operating loss
carryforwards available as a deduction against future AMT income.  In addition,
the Company had approximately $.5 million of investment tax credit carryforwards
and $7 million of percentage depletion carryforwards at December 31, 1997.  The
NOL carryforwards expire from 1998 through 2011.  The value of these
carryforwards depends on the ability of the Company to generate federal taxable
income.  In addition, for AMT purposes, only 90% of AMT income in any given year
may be offset by AMT NOL's.

     The ability of the Company to utilize NOL and investment tax credit
carryforwards to reduce future federal taxable income and federal income tax of
the Company 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 the offering of stock
by the Company during any three-year period resulting in an aggregate change of
more than 50% ("Ownership Change") in the beneficial ownership of the Company.

     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 (i) the fair market value of the equity of the Company multiplied by (ii) 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, the Company does not believe that an Ownership Change has occurred as of
December 31, 1997, or will occur as a result of the issuance of the preferred
stock in connection with the acquisition of the Celeron Companies.  See Item 1,
"Business--All American Pipeline Acquisition".    Equity transactions after the
date hereof by the Company or by 5% stockholders (including relatively small
transactions and transactions beyond the Company's control) could cause an
Ownership Change and therefore a limitation on the annual utilization of NOL's.

     In the event of an Ownership Change, the amount of the Company's NOL's
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.

     The Company does not expect to report any regular taxable income in the
near future because it expects to utilize its carryforwards and other tax
deductions and credits.  However, there is no assurance that the Internal
Revenue Service will not challenge these carryforwards or their utilization.

OTHER BUSINESS MATTERS

     The Company must continually acquire, explore for, develop or exploit new
oil and natural gas reserves to replace those produced or sold.  Without
successful drilling, acquisition or exploitation operations, the Company's oil
and natural gas reserves and revenues will decline.  Drilling activities are
subject to numerous risks, including the risk that no commercially viable 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

                                       18
<PAGE>
 
interpretations.  See Item 2, "Properties--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 the Company's oil and natural gas production also depends on a
number of factors, including the demand for and supply of oil and natural gas
and the proximity of reserves to pipelines or trucking and terminal facilities.
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 the Company's California crude oil and natural gas
production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could cause the Company to seek
transportation alternatives, which in turn could result in increased
transportation costs to the Company or involuntary curtailment of a significant
portion of its crude oil and natural gas production.

  The Company's operations are subject to all of the risks normally incident to
the exploration for and the production of oil and natural gas, including
blowouts, cratering, oil spills and fires, each of which could result in damage
to or destruction of oil and natural gas wells, production facilities or other
property, or injury to persons.  The relatively deep drilling conducted by the
Company from time to time involves increased drilling risks of high pressures
and mechanical difficulties, including stuck pipe, collapsed casing and
separated cable.  The Company's operations in the LA Basin, 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 the Company maintains insurance
coverage considered to be customary in the industry, it is not fully insured
against certain of these risks, including, in certain instances, earthquake risk
in the LA Basin, either because such insurance is not available or because of
high premium costs.  The occurrence of a significant event that is not fully
insured against could have a material adverse effect on the Company's financial
position.

  The revenues generated by the Company's operations are highly dependent upon
the prices of, and demand for, oil and natural gas.  Historically, the prices
for oil and natural gas have been volatile and are likely to continue to be
volatile in the future.  The price received by the Company for its oil and
natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors beyond the Company's control,
including seasonality, the condition of the United States economy (particularly
the manufacturing sector), foreign imports, political conditions in other 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 oil and natural gas have had, and
could have in the future, an adverse effect on the carrying value of the
Company's proved reserves and the Company's revenues, profitability and cash
flow.  A large portion of the Company's reserve base (approximately 94% of
year-end 1997 reserve volumes) is comprised of long-life oil properties that are
sensitive to crude oil price volatility.  The crude oil price received by the
Company at December 31, 1997, upon which proved reserve volumes, the Present
Value of Proved Reserves and the Standardized Measure as of such date were
based, was $18.34 per barrel. During the first quarter of 1998, the NYMEX Crude
Oil Price fluctuated significantly, closing as high as $17.82 per barrel and as
low as $13.21 per barrel. At March 23, 1998, the NYMEX Crude Oil Price was
approximately $16.50 per barrel. Although the Company is not currently
experiencing any significant involuntary curtailment of its crude oil or natural
gas production, market, logistic, economic and regulatory factors may in the
future materially affect the Company's ability to sell its production.

  In order to manage its exposure to price risks in the marketing of its oil and
natural gas, the Company from time to time enters into fixed price delivery
contracts, floating price collar arrangements, financial swaps and oil and
natural gas futures contracts as hedging devices.  To ensure a fixed price for
future production, the Company may sell a futures contract and thereafter either
(i) make physical delivery of its product to comply with such contract or (ii)
buy a matching futures contract to unwind its futures position and sell its
production to a customer.  These same techniques are also utilized to manage
price risk for certain production purchased from customers of Plains Marketing.
Such contracts may expose the Company to the risk of financial loss in certain
circumstances, including instances where production is less than expected, the
Company's customers fail to purchase or deliver the contracted quantities 

                                       19
<PAGE>
 
of oil or natural gas, or a sudden, unexpected event materially impacts oil or
natural gas prices. Such contracts may also restrict the ability of the Company
to benefit from unexpected increases in oil and natural gas prices. See Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Capital Resources, Liquidity and Financial Condition--Changing Oil
and Natural Gas Prices".

  Forward Looking-Statements and Associated Risks.  This Report includes
"forward-looking statements" within the meaning of various provisions of the
Securities Act and the Exchange Act.  All statements, other than statements of
historical facts, included in this Report which address activities, events or
developments that the Company expects or anticipates will or may occur in the
future, including such things as estimated future net revenues from oil and
natural gas reserves and the present value thereof, future capital expenditures
(including the amount and nature thereof), business strategy and measures to
implement strategy, competitive strengths, goals, expansion and growth of the
Company's business and operations, plans, references to future success,
references to intentions as to future matters and other such matters are
forward-looking statements.  These statements are based on certain assumptions
and analyses made by the Company in light of its experience and its perception
of historical trends, current conditions and expected future developments as
well as other factors it believes are appropriate in the circumstances.
However, whether actual results and developments will conform with the Company's
expectations and predictions is subject to a number of risks and uncertainties,
including general economic, market or business conditions, the opportunities (or
lack thereof) that may be presented to and pursued by the Company, competitive
actions by other oil and natural gas companies, changes in laws or regulations,
and other factors, many of which are beyond the control of the Company.
Consequently, all of the forward-looking statements made in this Report are
qualified by these cautionary statements and there can be no assurance that the
actual results or developments anticipated by the Company will be realized or,
even if substantially realized, that they will have the expected consequences to
or effects on the Company or its business or operations.

TITLE TO PROPERTIES

  The Company's 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.  The Company does not
believe that any of these burdens materially interferes with the use of such
properties in the operation of its business.

  The Company believes that it has generally satisfactory title to or rights in
all of its 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.

EMPLOYEES

  As of March 1, 1998, the Company had 230 full-time employees, none of whom is
represented by any labor union.  Approximately 103 of such full-time employees
are field personnel involved in oil and natural gas producing activities,
trucking and transport activities and crude oil terminalling and storage
activities.

ITEM 2.  PROPERTIES

  The Company is an independent energy company engaged in the acquisition,
exploitation, development, exploration and production of crude oil and natural
gas and the marketing, transportation, terminalling and storage of crude oil.
The Company's upstream oil and natural gas activities are focused in California
in the Los Angeles Basin and the Arroyo Grande Field, the Sunniland Trend and
the Illinois Basin.  The Company's midstream marketing, terminalling and storage
activities are concentrated in Oklahoma, Texas, the Gulf Coast area of Louisiana
and California.  The Company's upstream operations contributed approximately 87%
of the Company's EBITDA for the fiscal year ending December 31, 1997, while the
Company's midstream activities accounted for the remainder. The Company conducts
its upstream operations in each of its three core areas through wholly owned
subsidiaries.  The California Properties are operated by Stocker, the Sunniland
Trend properties are operated by Calumet and the Illinois Basin Properties are
operated by Plains Illinois.  The Company's midstream operations are conducted
through Plains 

                                       20
<PAGE>
 
Marketing. See Item 1, "Business" for a discussion of the Company's acquisition,
development, exploitation and exploration activities and midstream businesses.

OIL AND NATURAL GAS RESERVES

  The following tables set forth certain information with respect to the
Company's reserves based upon reserve reports prepared by the independent
petroleum consulting firms of H.J. Gruy and Associates, Inc. and System
Technology Associates Inc. with respect to the California Properties,
Netherland, Sewell & Associates, Inc. with respect to the Sunniland Trend and
other minor properties, and Ryder Scott Company with respect to the Illinois
Basin Properties.  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,
                               ---------------------------------------------------------------
                                      1997                  1996                  1995
                               -----------------    -------------------   --------------------
                                 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..........    115,996    37,273     94,408     43,110       61,459     51,009
Revisions of previous          
 estimates.................    (16,091)    3,805     19,424      6,641        5,423      2,792 
Extensions, discoveries,       
 improved recovery and                                                                  
   other additions.........     17,884     8,126      8,179      1,294       15,489      1,730   
Sale of reserves in place..        (26)     (547)        (5)   (12,491)      (1,227)    (9,773)
Purchase of reserves in         
 place.....................     40,764    14,566         45        862       17,640        130 
Production.................     (6,900)   (2,873)    (6,055)    (2,143)      (4,376)    (2,778)
                               -------    ------    -------    -------     --------     ------ 
Ending balance.............    151,627    60,350    115,996     37,273       94,408     43,110
                               =======    ======    =======    =======     ========     ======
PROVED DEVELOPED RESERVES                                                               
Beginning balance..........     86,515    25,629     67,266     29,397       48,978     30,869
                               =======    ======    =======    =======     ========     ======
Ending balance.............     99,193    38,233     86,515     25,629       67,266     29,397
                               =======    ======    =======    =======     ========     ======
</TABLE> 

     The following table sets forth the Present Value of Proved Reserves as of
December 31, 1997, 1996 and 1995.

<TABLE> 
<CAPTION> 
                                    1997         1996         1995
                                  --------     --------     --------
                                          (in thousands)
<S>                               <C>          <C>          <C> 
Proved developed...........       $386,463     $574,686     $272,634
Proved undeveloped.........        124,530      190,088       94,146
                                  --------     --------     --------
   Total proved............       $510,993     $764,774     $366,780
                                  ========     ========     ========
</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 the control of
the Company.  Reserve engineering is a subjective process of estimating the
recovery from underground accumulations of 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 oil and natural gas that are ultimately
recovered, production and operating costs, the amount and timing of future
development expenditures and future 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 oil and natural gas reserves
attributable to the Company's 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 the Company's

                                       21
<PAGE>
 
reserve base (approximately 94% of  year-end 1997 reserve volumes) is comprised
of long-life oil properties that are sensitive to crude oil price volatility.
The crude oil price received by the Company at December 31, 1997, 1996, and 1995
upon which proved reserve volumes, the Present Value of Proved Reserves and the
Standardized Measure as of such dates were based, was $18.34 per barrel, $25.92
per barrel and $19.55 per barrel, respectively.  Revisions of previous estimates
set forth above include downward price related revisions of 16 MMBls in 1997 and
positive price related revisions of 10 MMBbls in 1996.  During the first quarter
of 1998, the NYMEX Crude Oil Price fluctuated significantly, closing as high as
$17.82 per barrel and as low as $13.21 per barrel.  At March 23, 1998, the NYMEX
Crude Oil Price was approximately $16.50 per barrel.  See Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Capital Resources, Liquidity and Financial Condition--Changing Oil and Natural
Gas Prices".

     In accordance with the SEC guidelines, the reserve engineers' estimates of
future net revenues from the Company's properties and the present value thereof
are made using 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, 1997, is based on the NYMEX Crude Oil Price received by
the Company of $18.34 per barrel with variations therefrom based on location and
grade of crude oil.  The Company has entered into various fixed and floating
price collar arrangements to fix the NYMEX Crude Oil Price for a significant
portion of its crude oil production. On December 31, 1997, these arrangements
provided for a NYMEX Crude Oil Price for: (i) 12,250 barrels per day from
January 1, 1998, through December 31, 1998, at approximately $19.80 per barrel
and (ii) 2,000 barrels per day from January 1, 1999, through December 31, 1999,
at approximately $20.08 per barrel.  Since December 31, 1997, the Company has
entered into additional arrangements for 1999, which when combined with
arrangements in effect at December 31, 1997, provide for a NYMEX Crude Oil Price
for approximately 6,000 barrels per day from January 1, 1999, through December
31, 1999, at $18.55 per barrel.  Arrangements in effect at December 31, 1997,
are reflected in the reserve reports through the term of the arrangements.
Location and quality differentials attributable to the Company's properties are
not included in the foregoing prices.  The agreements provide for monthly
settlement based on the differential between the agreement price and the actual
NYMEX Crude Oil Price.  The overall average prices used in the reserve reports
as of December 31, 1997, were $13.91 per barrel of crude oil, condensate and
natural gas liquids and $2.13 per Mcf of natural gas.  See Item 1, "Business--
Product Markets and Major Customers".  Prices for natural gas and, to a lesser
extent, oil are subject to substantial seasonal fluctuations and prices for each
are subject to substantial fluctuations as a result of numerous other factors.

     Since December 31, 1996, the Company has not filed any estimates of total
proved net oil or natural gas reserves with any federal authority or agency
other than the SEC.  See Note 16 to the Company's Consolidated Financial
Statements appearing elsewhere in this Report for certain additional information
concerning the proved reserves of the Company.

PRODUCTIVE WELLS AND ACREAGE

     As of December 31, 1997, the Company had working interests in 1,767 gross
(1,758 net) active oil wells.  These totals do not include the Company's royalty
and overriding royalty interests in approximately 141 gross (5 net) producing
oil wells.

                                       22
<PAGE>
 
     The following table sets forth certain information with respect to the
developed and undeveloped acreage of the Company as of December 31, 1997.

<TABLE>
<CAPTION>
                                          DECEMBER 31, 1997
                             -------------------------------------------
                              DEVELOPED ACRES(1)    UNDEVELOPED ACRES(2)
                             ------------------     --------------------
                              GROSS       NET        GROSS       NET(3)
                             -------     ------     -------    ---------
<S>                          <C>         <C>        <C>        <C> 
California................     6,260      6,187          10         10
Florida(4)................    12,339     12,147      90,539     79,440
Illinois..................    15,887     13,885      33,528     15,459
Indiana...................     1,155        854       1,280        575
Kansas....................        --         --      48,147     37,807
Kentucky..................        --         --       1,321        521
Louisiana.................        --         --       4,875      4,858
                              ------     ------     -------    -------
     Total................    35,641     33,073     179,700    138,670
                              ======     ======     =======    =======
</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 4% of total net undeveloped acres are covered by leases that 
     expire from 1998 through 2001.
(4)  Does not include approximately 800,000 acres covered by the Exploration 
     Agreement entered into in February 1998 or 29,000 gross (28,000 net) 
     acres under seismic option.  See Item 1, "Exploration--Current Exploration
     Projects--Sunniland Trend".
 
DRILLING ACTIVITIES

     Certain information with regard to the Company's drilling activities during
the years ended December 31, 1997, 1996 and 1995 is set forth below:

<TABLE>
<CAPTION>
                                YEAR ENDED DECEMBER 31,
                       ----------------------------------------
                            1997         1996         1995
                       ------------  ------------  ------------
                       GROSS   NET   GROSS   NET   GROSS   NET
                       -----  -----  -----  -----  -----  -----
<S>                    <C>    <C>    <C>    <C>     <C>   <C> 
Exploratory Wells:
  Oil...............    2.00   2.00   0.00   0.00   0.00   0.00
  Natural gas.......    0.00   0.00   0.00   0.00   0.00   0.00
  Dry...............    0.00   0.00   2.00   0.63   1.00   0.40
                       -----  -----  -----  -----   ----   ---- 
      Total.........    2.00   2.00   2.00   0.63   1.00   0.40
                       =====  =====  =====  =====   ====   ====
Development Wells:                                       
  Oil...............   58.00  57.06  24.00  24.00   0.00   0.00
  Natural gas.......    0.00   0.00   0.00   0.00   0.00   0.00
  Dry...............    0.00   0.00   0.00   0.00   1.00   0.50
                       -----  -----  -----  -----   ----   ---- 
      Total.........   58.00  57.06  24.00  24.00   1.00   0.50
                       =====  =====  =====  =====   ====   ====
Total Wells:                                             
  Oil...............   60.00  59.06  24.00  24.00   0.00   0.00
  Natural gas.......    0.00   0.00   0.00   0.00   0.00   0.00
  Dry...............    0.00   0.00   2.00   0.63   2.00   0.90
                       -----  -----  -----  -----   ----   ---- 
      Total.........   60.00  59.06  26.00  24.63   2.00   0.90
                       =====  =====  =====  =====   ====   ====
</TABLE> 

     At December 31, 1997, the Company was in the process of drilling 7 gross (7
net) development wells.  See Item 1, "Business--Acquisition and Exploitation"
and "--Productive Wells and Acreage" for additional information regarding
exploitation activities, including waterflood patterns, workovers and
recompletions.

                                       23
<PAGE>
 
PRODUCTION AND SALES

     The following table presents certain information with respect to oil and
natural gas production attributable to the Company's 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, 1997, 1996
and 1995.

<TABLE>
<CAPTION>
                                                           Year Ended December 31,
                                                     ------------------------------------
                                                       1997          1996          1995
                                                     --------       -------       ------- 
                                                     (in thousands, except per unit data)
<S>                                                   <C>           <C>            <C>  
Production:                                                                  
   Crude oil and natural gas liquids (Bbls).....         6,900        6,055         4,376
   Natural gas (Mcf)............................         2,873        2,143         2,778
   BOE..........................................         7,379        6,412         4,839
Revenue:                                                                     
   Crude oil and natural gas liquids............      $104,988      $95,224       $61,241
   Natural gas..................................         4,415        2,377         2,839
                                                      --------      -------       -------
   Total........................................      $109,403      $97,601       $64,080
                                                      ========      =======       =======
Average sales price:                                                         
   Crude oil and natural gas liquids (per Bbl)..      $  15.21      $ 15.73       $ 13.99
   Natural gas (per Mcf)........................      $   1.54      $  1.11       $  1.02
   Per BOE......................................      $  14.83      $ 15.22       $ 13.24
Production expenses per BOE.....................      $   6.16      $  6.04       $  6.25

</TABLE>

CRUDE OIL STORAGE AND TERMINALLING FACILITIES

     In December 1993, the Company completed construction on the first phase of
the Cushing Terminal in Cushing, Oklahoma.  The first phase of the facility
consists of two million barrels of shell storage capacity comprised of fourteen
100,000 barrel capacity tanks and four 150,000 barrel capacity tanks.  In
addition, the Company owns a 360,000 barrel terminal and dock facility located
in Ingleside, Texas, just north of the Port of Corpus Christi.   See Item 1,
"Business -- Midstream Activities".

OTHER FACILITIES

     The Company currently leases offices containing approximately 42,000 square
feet in Houston, Texas.

ITEM 3.   LEGAL PROCEEDINGS

          On July 9, 1987, Exxon filed an interpleader action in the United
States District Court for the Middle District of Florida, Exxon Corporation v.
E. W. Adams, et al., Case Number 87-976-CIV-T-23-B.  This action was filed by
Exxon to interplead royalty funds as a result of a title controversy between
certain mineral owners in a field in Florida.  One group of mineral owners, John
W. Hughes, et al. (the "Hughes Group"), filed a counterclaim against Exxon
alleging fraud, conspiracy, conversion of funds, declaratory relief, federal and
Florida RICO, breach of contract and accounting, as well as challenging the
validity of certain oil and natural gas leases owned by Exxon, and seeking
exemplary and treble damages.  In March 1993, but effective November 1, 1992,
Calumet, a wholly-owned subsidiary of the Company, acquired all of Exxon's
leases in the field affected by this lawsuit.  In order to address those
counterclaims challenging the validity of certain oil and natural gas leases,
which constitute approximately 10% of the land underlying this unitized field,
Calumet filed a motion to join Exxon as plaintiff in the subject lawsuit, which
was granted July 29, 1994.  In August 1994, the Hughes Group amended its
counterclaim to add Calumet as a counter-defendant.  Exxon and Calumet filed a
motion to dismiss the counterclaims.  On March 22, 1996, the Court granted
Exxon's and Calumet's motion to dismiss the counterclaims alleging fraud,
conspiracy, and federal and Florida RICO violations and challenging the validity
of certain of the Company's oil and natural gas leases but denied such motion as
to the counterclaim alleging conversion of funds.  The Company has reached an
agreement in principle with all parties to settle this case.  In consideration
for full and final settlement, and dismissal with prejudice of all issues in
this case, the Company has agreed

                                       24
<PAGE>
 
to pay to the defendants the total sum of $100,000, and release certain
royalty amounts held in suspense and in the court registry during the pendency
of this case.  Finalization of this settlement has been delayed due to disputes
over certain title issues.  Motions have been filed requesting the Court to rule
on the disputes, but no hearing date has been set.  The Company does not believe
that the disputes will adversely affect the settlement reached between the
Company and the defendants.

          The Company, in the ordinary course of business, is a claimant and/or
a defendant in various other legal proceedings in which its exposure,
individually and in the aggregate, is not considered material to the Company.

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 the executive officers of the Company 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 39, has been President, Chief Executive Officer and
a director of the Company 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., Senior Vice President                   Officer Since 1984

          Mr. Egg, age 46, has been Senior Vice President of the Company since
1991.  He was Vice President-Corporate Development of the Company from 1984 to
1991 and Special Assistant-Corporate Planning from 1982 to 1984.

Cynthia A. Feeback, Controller and Principal Accounting 
  Officer                                                    Officer Since 1993

          Ms. Feeback, age 40, has been Controller and Principal Accounting
Officer of the Company since 1993.  She was Controller of the Company from 1990
to 1993 and Accounting Manager from 1988 to 1990.

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

          Mr. Kramer, age 42, became Senior Vice President and Chief Financial
Officer of the Company in May 1997.  He was Vice President and Chief Financial
Officer from 1992 to 1997, Vice President and Treasurer from 1988 to 1992,
Treasurer from 1987 to 1988, and Controller from 1983 to 1987.

Michael R. Patterson, Vice President and General Counsel     Officer Since 1985

          Mr. Patterson, age 50, has been Vice President and General Counsel of
the Company since 1985 and Corporate Secretary since 1988.

Harry N. Pefanis, Senior Vice President                      Officer Since 1988

          Mr. Pefanis, age 40, became Senior Vice President in February 1996.
He had been Vice President-Products Marketing of the Company since 1988.  From
1987 to 1988 he was Manager of Products Marketing.  From 1983 to 1987 he was
Special Assistant for Corporate Planning for the Company.  Mr. Pefanis is also
President of Plains Marketing & Transportation Inc., a wholly-owned subsidiary
of the Company.

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

          Ms. Peters, age 49, has been Vice President-Administration and Human
Resources since 1991.  She was Manager of Office Administration of the Company
from 1984 to 1991.

                                       25
<PAGE>
 
                                    PART II

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

          The Company's $.10 par value 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 20, 1998, was 1,409.

          For the periods indicated below, 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.

<TABLE>
<CAPTION>
 
                        High        Low
                     ---------   ---------
<S>                  <C>         <C> 
1997:
1st Quarter.......   $18   1/4   $12   
2nd Quarter.......    15  3/16    11   7/8
3rd Quarter.......    18   1/2    15   
4th Quarter.......    20   3/4    15   7/8
            
1996:       
1st Quarter.......   $ 9   1/8   $ 7  7/16
2nd Quarter.......    13           8   1/2
3rd Quarter.......    14   7/8    11   3/4
4th Quarter.......    16   5/8    12   7/8
</TABLE>

     The Company has not paid cash dividends on shares of the Common Stock since
the Company's inception and does not anticipate paying any cash dividends on the
Common Stock in the foreseeable future.  In addition, the Company is prohibited
by provisions of the indenture governing the issue of $200 million 10.25% Senior
Subordinated Notes Due 2006 (the "10.25% Notes") and the Company's $165 million
revolving credit facility (the "Revolving Credit Facility") from paying
dividends on the Common Stock.

                                       26
<PAGE>
 
ITEM 6.  SELECTED FINANCIAL DATA

     The following selected historical financial information was derived from,
and is qualified by reference to, the Consolidated Financial Statements of the
Company, 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".

<TABLE>
<CAPTION>
                                                                                     YEAR ENDED DECEMBER 31,
                                                                 -------------------------------------------------------------------

                                                                    1997         1996          1995        1994         1993
                                                                 ----------   ---------     ---------    ---------   ----------
<S>                                                            <C>             <C>           <C>         <C>         <C> 
                                                                   (IN THOUSANDS, EXCEPT PER SHARE INFORMATION)
STATEMENT OF INCOME DATA:
Revenues:
   Oil and natural gas sales...................................    $109,403    $ 97,601       $ 64,080    $ 57,234     $ 57,507
   Marketing, transportation and storage.......................     752,522     531,698        339,826     199,239      128,186
   Other.......................................................         319         309            319         223          335
                                                                   --------    --------       --------    --------     --------
      Total revenue............................................     862,244     629,608        404,225     256,696      186,028
                                                                   --------    --------       --------    --------     --------
Expenses:
   Production expenses.........................................      45,486      38,735         30,256      27,220       28,285
   Purchases, transportation and storage.......................     740,042     522,167        333,460     193,049      124,390
   General and administrative..................................       8,340       7,729          7,215       6,966        7,724
   Depreciation, depletion and amortization....................      23,778      21,937         17,036      16,305       36,980(1)
   Interest expense............................................      22,012      17,286         13,606      12,585        8,847
   Litigation settlement.......................................          --       4,000(2)          --          --           --
                                                                   --------    --------       --------    --------     --------
      Total expenses...........................................     839,658     611,854        401,573     256,125      206,226
                                                                   --------    --------       --------    --------     --------
Income (loss) before income taxes and extraordinary item.......      22,586      17,754          2,652         571      (20,198)
Income tax expense (benefit)
   Current.....................................................         352          --             --          --           --
   Deferred....................................................       7,975      (3,898)            --          --           --
                                                                   --------    --------       --------    --------     --------
Income (loss) before extraordinary item........................      14,259      21,652          2,652         571      (20,198)
Extraordinary item, net of tax benefit.........................          --      (5,104)(3)         --          --           --
                                                                   --------    --------       --------    --------     --------
Net income (loss)..............................................    $ 14,259    $ 16,548       $  2,652    $    571     $(20,198)
                                                                   ========    ========       ========    ========     ========

Earnings (loss) per common share - basic:
   Before extraordinary item...................................    $   0.85    $   1.32       $   0.19    $   0.04     $  (1.77)
   Extraordinary item, net of income taxes.....................           -       (0.31)            --          --           --
                                                                   --------    --------       --------    --------     --------
                                                                   $   0.85    $   1.01       $   0.19    $   0.04     $  (1.77)
                                                                   ========    ========       ========    ========     ========

Earnings (loss) per common share - assuming dilution:
   Before extraordinary item...................................    $   0.77    $   1.23       $   0.16    $   0.04     $  (1.77)
   Extraordinary item, net of income taxes.....................           -        (.29)            --          --           --
                                                                   --------    --------       --------    --------     --------
                                                                   $   0.77    $   0.94       $   0.16    $   0.04     $  (1.77)
                                                                   ========    ========       ========    ========     ========

OTHER FINANCIAL DATA:
Cash flow from operations(4)...................................    $ 46,233    $ 39,942       $ 19,688    $ 16,876     $ 16,782
EBITDA(5)......................................................      68,310      57,184         33,294      29,461       25,629
Net cash provided by operating activities......................      30,307      39,008         16,984      18,369       10,397
Net cash used in investing activities..........................     107,634      52,496         64,398      40,158       76,451
Net cash provided by financing activities......................      78,524       9,876         52,252      19,297       44,688
</TABLE>

<TABLE>
<CAPTION>
                                                                                            AS OF DECEMBER 31,
                                                                   --------------------------------------------------------------
                                                                     1997          1996           1995         1994        1993
                                                                   ---------    ---------      ----------    ---------   --------
<S>                                                                <C>          <C>            <C>           <C>         <C>
                                                                                                  (IN THOUSANDS)
BALANCE SHEET DATA:
Cash and cash equivalents......................................    $  3,714     $  2,517        $  6,129     $  2,791    $  4,862
Working capital (deficit)......................................      (6,011)      (4,843)         (4,749)      (4,465)    (13,986)
Property and equipment, net....................................     413,308      311,040         280,538      217,602     191,985
Total assets...................................................     556,819      430,249         352,046      266,904     236,667
Long-term debt.................................................     285,728      225,399         205,089      149,600     141,600
Other long-term liabilities....................................       5,107        2,577           1,547        3,754         967
Redeemable preferred stock.....................................          --           --              --       20,937          --
Total stockholders' equity.....................................     133,193       95,572          77,029       46,462      44,997
</TABLE> 
 
(1)  Includes a $20 million non-cash charge related to a writedown of the
     capitalized costs of the Company's proved oil and natural gas properties
     due to low crude oil prices at December 31, 1993. 
(2)  Represents charge related to the settlement of two lawsuits filed in 1992
     and 1993. See Item 7, "Management's Discussion and Analysis of Financial
     Condition and Results of Operations--Results of Operations".
(3)  Relates to the early redemption in March 1996 of the Company's 12% Senior
     Subordinated Notes due 1999.
(4)  Net cash provided by operating activities before changes in assets and 
     liabilities.
(5)  EBITDA means earnings before interest, taxes, depreciation, depletion,
     amortization and other noncash items. 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. 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.

                                       27
<PAGE>
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
        RESULTS OF OPERATIONS

GENERAL

     For the three years ended December 31, 1997, the Company reported continued
improvement in its fundamental operating and financial results.  Upstream
production volumes and midstream gross margin, the primary operating drivers for
each segment, were up significantly in 1997, versus 1996 and 1995.  For the
three years ended December 31, 1997, the Company also reported significant
increases in proved reserves and cash flow from oil and natural gas producing
activities.  Such increases are primarily the result of acquisition and
exploitation activities in the Company's three core areas of California, the
Sunniland Trend  and the Illinois Basin.  During 1997, the Company added to it's
existing LA Basin Properties with the acquisition of the Montebello Field in
March, and expanded into another California area with the acquisition of the
Arroyo Grande Field in November.  Combined, these two fields added approximately
43 million BOE to the Company's proved reserves at the acquisition dates.  The
Company's three core areas are comprised primarily of crude oil properties and
together account for approximately 99% of the Company's year-end 1997 proved
reserves.  See Item 1, "Business--Acquisition and Exploitation--Current
Exploitation Projects".

RESULTS OF OPERATIONS

     For the year ended December 31, 1997, the Company reported net income of
$14.3 million, or $.85 per share ($.77 per share assuming dilution), on total
revenue of $862.2 million compared to net income for 1996 of $16.5 million, or
$1.01 per share ($.94 per share assuming dilution).  Net income for 1995 was
$2.7 million or $.19 per share ($.16 per share assuming dilution).  Earnings per
share for 1996 and 1995 has been restated in accordance with the provisions of
Statement of Financial Accounting Standards No. 128, Earnings per Share.  For
1997, the Company reported pretax income of $22.6 million as compared to $17.8
million of pretax income in 1996 on higher oil prices.  Net income for 1996
included an $11.0 million benefit associated with the recognition of a portion
of a deferred tax asset that was previously fully reserved  and a $5.1 million
extraordinary charge net of taxes for early extinguishment of debt.  EBITDA
increased 19% in 1997 to $68.3 million from the $57.2 million reported in 1996
and 105% from the $33.3 million reported in 1995.  Cash flow from operations
(cash provided by operating activities before changes in assets and liabilities)
increased to $46.2 million in 1997, 16% and 135% above the $39.9 million and
$19.7 million reported in 1996 and 1995, respectively.  Net cash provided by
operating activities was $30.3 million for the year ended December 31, 1997, as
compared to $39.0 million for 1996 and $17.0 million in 1995.  The decrease in
1997 from 1996 is attributable to the purchase of crude oil inventory in
contango market transactions. Such inventory was hedged against price risk and
was sold during the first quarter of 1998.

                                       28
<PAGE>
 
Upstream Results
 
     The following table sets forth certain operating information of the Company
for the periods presented:

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                      --------------------------------------
                                                       1997            1996            1995
                                                      ------          ------          ------
<S>                                                   <C>             <C>             <C>
                                                     (IN THOUSANDS, EXCEPT PER UNIT DATA)
AVERAGE DAILY PRODUCTION VOLUMES
Barrels of oil equivalent:
   California (approximately 89% oil).............      11.2             9.2             8.4
   Sunniland Trend (100% oil).....................       5.3             4.7             3.4
   Illinois Basin (100% oil)......................       3.6             3.5             0.6
   Other..........................................       0.1             0.1             0.9
                                                      ------          ------          ------
      Total.......................................      20.2            17.5            13.3
                                                      ======          ======          ======

UNIT ECONOMICS
   Average sales price per BOE....................    $14.83          $15.22          $13.24
   Production expenses per BOE....................      6.16            6.04            6.25
                                                      ------          ------          ------
   Gross margin per BOE...........................      8.67            9.18            6.99
   Upstream G&A expenses per BOE..................      0.65            0.74            0.99
                                                      ------          ------          ------
   Gross profit per BOE...........................    $ 8.02          $ 8.44          $ 6.00
                                                      ======          ======          ======
</TABLE>

     Oil and natural gas production volumes in 1997 totaled 7.4 million BOE, a
15% increase over the 1996 level of 6.4 million BOE and 52% above the 1995 level
of 4.8 million BOE.  Approximately 94% of 1997's equivalent production volumes
were crude oil. Production volumes increased in each of the Company's three core
areas due to the Company's acquisition and exploitation activities.  Average net
daily production from the Company's California Properties increased to
approximately 11,200 BOE per day in 1997, up 2,000 BOE per day, or 22% over 1996
and  33% over the 1995 level.  Excluding production from the Montebello and
Arroyo Grande Fields which were acquired during 1997, aggregate Company
production was up 8% from 1996.  Net production from the Company's Sunniland
Trend properties averaged approximately 5,300 barrels of oil per day in 1997, a
13% increase compared to 4,700 barrels per day in 1996 and 56% over the 3,400
barrels per day in 1995.  Due to the high volume of production that is generated
by very few wells in the Sunniland Trend, abrupt or abnormal declines or
downtime due to mechanical, marketing, or other conditions on any of the
properties in this area could have a significant impact on production.  Net
daily production in the Illinois Basin averaged approximately 3,600 barrels per
day during 1997, up 3% over 1996.  The Company acquired the Illinois Basin
properties in the fourth quarter of 1995.

     Oil and natural gas revenues increased to $109.4 million in 1997 as
compared to $97.6 million in 1996 and $64.1 million in 1995 due to increased
production volumes.  The Company's average product price, which represents a
combination of fixed and floating price sales arrangements and incorporates
location and quality discounts from the benchmark NYMEX prices, averaged $14.83
per BOE in 1997, a 3% decrease from the average price received in 1996, and an
increase of 12% from the  $13.24 per BOE in 1995.  The NYMEX Crude Oil Price
averaged $20.63 per barrel in 1997, $21.99 per barrel in 1996, and $18.40 per
barrel in 1995.  Financial swap arrangements and futures transactions entered
into by the Company to hedge production are included in the Company's average
product prices.  Such transactions had the effect of decreasing the overall
average price per BOE received by the Company by $1.26 in 1997, $2.62 in 1996
and $.17 in 1995. Approximately 78% of the Company's crude oil production was
hedged throughout 1997 at an average NYMEX Crude Oil Price of approximately
$19.31 per barrel.  The Company routinely hedges a portion of its crude oil
production.  See "--Capital Resources, Liquidity and Financial Condition--
Changing Oil and Natural Gas Prices".

     Upstream unit gross margin (well-head revenue less production expenses) for
1997 was $8.67 per BOE, compared to $9.18 per BOE in 1996 and $6.99 per BOE in
1995.  Average unit production expenses were $6.16 per BOE, $6.04 per BOE and
$6.25 per BOE in 1997, 1996, and 1995, respectively. Total production expenses
increased to $45.5 million from $38.7 million and $30.3 million in 1996 and
1995, respectively, primarily due to increased production volumes resulting from
the Company's acquisition and exploitation activities.

                                       29
<PAGE>
 
     Unit G&A expense in the upstream segment decreased for the fifth
consecutive year.  Unit G&A expense decreased 12% to $.65 per BOE during 1997
from $.74 per BOE during 1996.  Unit G&A expense was $.99 per BOE in 1995, $1.04
per BOE in 1994, $1.34 per BOE in 1993 and $2.48 per BOE in 1992.  These
reductions were directly attributable to increased production levels and to the
Company's ongoing cost control efforts.

     As a result of the warm and abnormal weather generally referred to as El
Nino, weather patterns throughout the United States have experienced meaningful
variances from historical norms.  In particular, California has been
significantly affected by unusually large amounts of rainfall.  Through mid-
March 1998, areas within California where the Company's properties are located
have experienced actual rainfall exceeding 150% of the rainfall typically
received for an entire year.  Such rainfall and associated high winds have an
adverse effect on the Company's California operations.  Specifically, such
weather conditions cause erosion, flooding, electrical outages and various other
related side effects.  Such conditions result in reduced production due to down
time and delays in implementing capital projects, as well as increased expenses
associated with repair and mitigation costs.

     Through mid-March, aggregate production down time caused by El Nino was
estimated at approximately 20,000 barrels and incremental operating expenses
were estimated at approximately $500,000.  While the Company believes it has
taken appropriate steps to mitigate the adverse effects of El Nino on its
operations, there can be no assurance that the preventative measures will prove
effective, and the Company cannot predict the extent to which such adverse
weather patterns will continue to impact the Company's 1998 operations,
financial results or planned capital program.

Midstream Results

     The following table sets forth certain midstream operating information of
the Company for the periods presented:

<TABLE>
<CAPTION>
                                                           YEAR ENDED DECEMBER 31,
                                                     ------------------------------------
                                                       1997          1996          1995
                                                     --------      --------      --------
<S>                                                  <C>           <C>           <C>
                                                                 (IN THOUSANDS)
OPERATING RESULTS
   Gross margin.................................      $12,480       $ 9,531       $ 6,366
   G&A expense..................................       (3,529)       (2,974)       (2,415)
                                                      -------       -------       -------
   Gross profit.................................      $ 8,951       $ 6,557       $ 3,951
                                                      =======       =======       =======
 
AVERAGE DAILY VOLUMES
   Crude oil barrels marketed...................           71            59            46
   Crude oil terminal throughput barrels........           69            56            42
                                                      -------       -------       -------
                                                          140           115            88
                                                      =======       =======       =======
</TABLE>

    The Company's midstream segment reported gross margin (revenues less direct
expenses of purchases, transportation, storage and terminalling) of $12.5
million for the year ended December 31, 1997, reflecting a 31% increase over the
$9.5 million reported for the 1996 period and an approximate 96% increase over
1995.  Gross profit, which deducts G&A expenses attributable to this segment,
totaled $9.0 million for 1997, approximately  37% and 127% over  the amounts
reported for 1996 and 1995, respectively.  Net of interest expense associated
with contango inventory transactions, midstream gross margin and gross profit
for the current year were $11.6 million and $8.1 million, respectively,
representing increases of approximately 22% and 23% over the 1996 respective
amounts.  Gross revenues from this segment were $752.5 million, $531.7 million
and $339.8 million for 1997, 1996 and 1995, respectively.  The increases in
revenues and profitability are primarily due to increased volumes marketed and
activities at the Cushing Terminal.  The Company's terminalling and storage
activities are generally counter cyclical to its crude oil marketing activities.
Typically, marketing margins are strongest in a backward market.  During a
contango market, when marketing margins are generally smaller, the Company's
terminalling and storage operations at the Cushing Terminal typically become
more profitable due to (i) the Company's ability to take delivery on crude oil
which is simultaneously purchased and resold at a profit for delivery in a
subsequent month and (ii) the increased demand by third parties for storage
capacity.  Storage and terminalling margins were generally stronger in 1997, and
marketing margins were stronger in 1996 and 1995.  Aggregate marketing and
terminalling volumes averaged 140,000 barrels per day in 1997 versus 115,000
barrels per day in 1996 and 88,000 barrels per day in 1995.  Midstream G&A
expenses were $3.5 million, $3.0 

                                       30
<PAGE>
 
million, and $2.4 million for 1997, 1996 and 1995, respectively. Such increases
are primarily attributable to the continued expansion of the Company's marketing
and terminalling activities.

General

    Total G&A expenses, including midstream activities, were $8.3 million for
the year ended December 31, 1997, compared to $7.7 million and $7.2 million for
1996 and 1995, respectively.  The increases are primarily attributable to
increased expenses associated with the Company's midstream activities.
Depreciation, depletion and amortization ("DD&A") per BOE declined to $2.83 in
1997 from $3.00 in 1996 and $3.02 in 1995 primarily as a result of the Company's
acquisition and exploitation activities.  Primarily as a result of increased
production levels, total DD&A for the year ended December 31, 1997 was $23.8
million as compared to $21.9 million and $17.0 million in 1996 and 1995,
respectively.

    Interest expense, net of capitalized interest, for 1997 increased to $22.0
million as compared to $17.3 million in 1996 and $13.6 million in 1995.  The
increases are primarily due to (i) higher debt levels related to the Company's
acquisition, exploitation, development and exploration activities, including the
acquisition of the Montebello Field, (ii) short-term borrowings in 1997 for the
purchase of crude oil inventory associated with contango crude oil inventory
transactions and (iii) a higher average interest rate, partially attributable to
the $50 million add-on to the 10.25% Notes in July 1997.  During 1997, 1996 and
1995, the Company capitalized $3.3 million, $3.6 million and $3.1 million of
interest, respectively.

    During 1996, the Company settled two lawsuits filed in 1992 and 1993,
relating to activities in 1991 and 1992,  against certain of its officers and
directors for a cash payment of approximately $6.3 million.  Approximately $4.1
million of such amount was paid by the Company's insurance carrier and $2.2
million was paid by the Company.  Taking into account prior costs incurred by
the Company to defend these suits, and for which the Company agreed to
relinquish its claims for reimbursement against its insurance company, this
settlement resulted in a charge to 1996 first quarter earnings of $4 million.

    For the year ended December 31, 1997, the Company recognized a deferred tax
provision of $8.0 million and a current tax provision of $.4 million.  For 1996,
the Company recognized a net deferred tax benefit before extraordinary item of
$3.9 million.  Such amount consists of a $7.1 million deferred tax provision on
the Company's income before extraordinary item and an $11.0 million reduction in
the valuation allowance reserved against the Company's net deferred tax asset.
In 1996, the Company also reported a $3.4 million deferred tax benefit as an
extraordinary item which was attributable to the $8.5 million pre-tax first
quarter extraordinary loss from the early redemption of the Company's 12% Senior
Subordinated Notes due 1999 (the "12% Notes").  Although the Company recorded
net income for 1995, no provision for income taxes was reflected, but rather the
valuation allowance discussed above was adjusted.

    The Company has initiated a comprehensive review of its computer systems to
identify the systems that could be affected by the "Year 2000" issue.  The
Company expects to incur internal staff costs as well as some consulting and
other expenses necessary to prepare the systems for the year 2000.  The Company
does not expect the amounts required to be expensed over the next year to have a
material effect on its results of operations.  The Company expects all Year 2000
issues to be resolved in a timely manner during 1998 and 1999.  There can be no
assurance that the systems of other companies on which the Company relies also
will be converted in a timely manner or that any such failure to convert by
another company would not have an adverse effect on the Company.  In order to
minimize this impact, the Company is in contact with its vendors and customers
to work toward their compliance.

    In July 1997, the FASB issued Statement of Financial Accounting Standards
No. 131 ("SFAS 131"), Disclosures About Segments of an Enterprise and Related
Information, effective for fiscal years beginning after December 15, 1997.  SFAS
131 introduces a new model for segment reporting and requires disclosures for
each segment that are similar to those required under current standards with the
addition of quarterly disclosure requirements and a finer partitioning of
geographic disclosures.  Reportable segments are based on products and services,
geography, legal structure, management structure or any manner in which
management disaggregates a company.  This statement replaces the notion of
industry and geographic segments in current FASB standards.  Management is
currently evaluating the impact of this statement on the Company's disclosures.

                                       31
<PAGE>
 
CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION

    In March 1997, the Company completed the acquisition of Chevron's interest
in the Montebello Field for approximately $25 million, effective February 1,
1997.  The assets acquired consist of a 100% working interest and a 99.2% net
revenue interest in 55 producing oil wells and related facilities and also
include approximately 450 acres of surface fee land.  At the acquisition date,
the Montebello Field, which is located approximately 15 miles from the Company's
existing LA Basin operations, was producing approximately 800 barrels of oil and
800 Mcf of gas per day and added approximately 23 million barrels of oil
equivalent to the Company's proved reserves.  As a result of high intert
content, the Company's gas production in the Montebello Field is difficult to
market and currently is delivered for no value.  To ensure that the Company is
able to develop and produce its oil reserves without restriction due to lack of
markets, the Company has made arrangements with the former owner of the
Montebello Field to take its natural gas production volumes at no incremental
value when the Company is unable to find a market for the gas.  The Company
intends to spend approximately $2.5 million during 1998 and 1999 to improve the
quality of the gas through upgrading and refining the existing gas collection
system, as well as adding additional processing capacity.  The Company believes
that this will enable it to obtain an alternative market for the gas production,
although such market cannot be assured.  See Item 1, "Business--Product Markets
and Major Customers".  The Montebello Acquisition was funded with proceeds from
the Revolving Credit Facility.

    On November 12, 1997, the Company acquired a 100% working interest and a 97%
net revenue interest in the Arroyo Grande Field in San Luis Obispo County,
California, from subsidiaries of Shell.  The assets acquired include surface and
development rights to approximately 1,000 acres included in the 1,500 acre unit.
At the acquisition date, the field was producing approximately 1,600 barrels
(approximately 1,500 barrels net to the Company) of 14(degree) API gravity oil
per day from 70 wells.

    The aggregate purchase price of $22.1 million consisted of (i) rights to a
non-producing property interest conveyed to Shell, (ii) the issuance of 46,600
shares of Series D Preferred Stock with an aggregate stated value of $23.3
million and (iii) a 5 year warrant to purchase 150,000 shares of Common Stock at
$25 per share.  No proved reserves had been assigned to the rights to the
property interest conveyed.  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.  Commencing January
1, 2000, the Series D Preferred Stock will bear an annual dividend of $30.00 per
share.  Prior to such date no dividends will accrue.  The Series D Preferred
Stock is redeemable at the Company's 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.  The Series D
Preferred Stock was initially recorded at $20.5 million, a discount of $2.8
million from the stated value.  This discount will be amortized to retained
earnings during the two year period dividends do not accrue.

    In March 1997, the Company's Revolving Credit Facility and borrowing base
thereunder was increased to $165 million from $125 million.  The Revolving
Credit Facility, as amended, converts to a term loan on July 1, 1999, with a
final maturity of July 1, 2004, and bears interest at the option of the Company
at LIBOR plus 1 3/8% or Base Rate (as defined therein).  The Revolving Credit
Facility is guaranteed by all of the Company's subsidiaries except PMCT Inc. and
Plains All American and is secured by the upstream oil and gas properties
of the Company and the guaranteeing subsidiaries and the stock of all
subsidiaries except Plains All American.  At December 31, 1997, the Company
had $80 million in borrowings and a $1.0 million standby letter of credit
outstanding under the Revolving Credit Facility.

    On July 23, 1997, the Company sold $50 million of Senior Subordinated Notes
due 2006, Series C, bearing  a stated coupon rate of 10.25% (the "Series C
10.25% Notes").  Such notes were issued pursuant to a Rule 144A private
placement at approximately 107.21% of par to yield a minimum yield to worst of
8.79%, or 9.03% yield to maturity.  On October 30, 1997, the Company exchanged a
total of $49.95 million of the Series C 10.25% Notes for 10.25% Senior
Subordinated Notes due 2006, Series D, (the "Series D 10.25% Notes").  The
Series D 10.25% Notes are substantially identical (including principal amount,
interest rate, maturity and redemption rights) to the Series C 10.25% Notes for
which they were exchanged, except for certain transfer restrictions relating to
the Series C 10.25% Notes.  Proceeds from the sale of the Series C & D 10.25%
Notes, net of offering costs, were approximately $53 million and were used to
reduce the balance outstanding on the Revolving Credit Facility.

                                       32
<PAGE>
 
    The stated coupon rate of interest and maturity date of the Series C 10.25%
Notes and the Series D 10.25% Notes (collectively, the "Series C & D 10.25%
Notes") are the same as those of the Company's existing $150 million principal
amount of senior subordinated notes currently outstanding (the "Series A & B
10.25% Notes").  The Series A 10.25% Notes, the Series B 10.25% Notes, the
Series C 10.25% Notes and the Series D 10.25% Notes (collectively, the "10.25%
Notes") are redeemable, at the option of the Company, 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.  In addition,
prior to March 15, 1999, up to $45 million in principal amount of the Series A &
B 10.25% Notes and up to $15 million in principal amount of the Series C & D
10.25% Notes are redeemable at the option of the Company, in whole or in part,
from time to time, at 110.25% of the principal amount thereof, with the Net
Proceeds of any Public Equity Offering (as both are defined in the indenture
under which the 10.25% Notes were issued (the "Indenture")).

    Plains Marketing has a $90 million Uncommitted Secured Demand Transactional
Line of Credit Facility (the "Transactional Facility") with five banks.  The
purpose of the Transactional Facility is to provide standby letters of credit to
support the purchase of crude oil for resale and borrowings to finance crude oil
inventory that has been hedged against future price risk.  In August 1997, the
sublimit for cash borrowings under the Transactional Facility was increased to
$25 million from $20 million.  Letters of credit under the Transactional
Facility are generally issued for seventy-day periods and bear fees of 1 1/8%
per annum.  Borrowings incur interest at the option of the borrower at (i) the
Base Rate or (ii) LIBOR plus 1 1/2%.  At December 31, 1997, approximately $37.8
million in letters of credit and $18.0 million in borrowings were outstanding
under the Transactional Facility.

    The Transactional Facility is secured by all of the assets of Plains
Marketing and is guaranteed by the Company.  The Company's guarantee is secured
by a $1.0 million standby letter of credit issued on behalf of the Company.  All
financings under the Transactional Facility, which expires in November 1998, are
at the discretion of the lenders.

    At December 31, 1997, the Company had a working capital deficit of
approximately $6.0 million.  The Company has historically operated with a
working capital deficit due primarily to ongoing capital expenditures that have
been financed through cash flow and the Revolving Credit Facility.  The working
capital deficits at December 31, 1996 and 1995, were $4.8 million and $4.7
million, respectively.

    On March 21, 1998, Plains All American entered into a definitive agreement
to acquire all of the outstanding capital stock of the Celeron Companies from
Goodyear.  Aggregate proceeds to Goodyear through closing are estimated at $420
million.  The principal assets of the entities to be acquired include the All
American Pipeline System, a 1,233-mile crude oil pipeline extending from
California to Texas, and a 45-mile crude oil gathering system in the San Joaquin
Valley of California, as well as other assets related to such operations.  The
purchase price is subject to certain adjustments through the closing date, and
the transaction is subject to regulatory review and approval by the United
States Department of Justice and the Federal Trade Commission under the Hart-
Scott-Rodino Anti-Trust Improvements Act of 1976, as amended, and by the Public
Utilities Commission of the State of California.   The transaction is expected
to be completed in the third quarter of 1998 after regulatory approvals have
been secured.

    A major source of financing for the transaction will be provided through a
new $325 million, limited recourse bank facility made available to Plains All
American by ING Barings and BankBoston, N.A.  In addition to the bank facility,
the Company will make a capital contribution to Plains All American of up to
$130 million which will be used to fund the balance of the purchase price and
transaction costs and provide initial working capital.  To finance its capital
contribution, the Company will borrow approximately $50 million under the
Revolving Credit Facility and has entered into financing commitments for a new
issue of privately placed, convertible preferred stock aggregating approximately
$80 million. Commitments for the preferred stock placement have been obtained
from a group of equity investors comprised primarily of existing shareholders.
The preferred stock has an aggregate stated value of $80 million and bears a
cumulative dividend of 9.5% per annum, payable semi-annually in either cash or
additional shares of preferred stock  at the Company's option.  Each share of
preferred stock is convertible into 27.78 shares of Common Stock (an effective
conversion price of $18.00 per share) and in certain circumstances may be
converted at the Company's 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.
The preferred stock is redeemable at the option of the Company at 110% of stated
value after March 31, 1999, and at 

                                       33
<PAGE>
 
declining amounts thereafter. If not previously redeemed or converted, the
preferred stock is required to be redeemed in 2012.

    The All American Pipeline is the single largest crude oil pipeline
connecting California to West Texas, where it connects with pipelines that
transport crude oil to Cushing, Oklahoma and the Gulf Coast.  The Cushing
Interchange is the largest crude oil trading location in the United States and
the designated delivery point for the NYMEX crude oil futures contract.  At
Cushing, the Company owns and operates the Cushing Terminal, the largest
terminal facility in Cushing not owned by a major oil company and the fourth
largest overall.  The 45-mile gathering system is located in the San Joaquin
Valley, currently the most prolific crude oil producing region in the
continental United States.  The areas serviced by the pipeline and gathering
system currently produce over 700,000 barrels of crude oil per day, representing
approximately 15% of total oil production in the continental United States.  For
1997, the operations to be acquired generated approximately $65 million in
EBITDA.

    The Company has made and will continue to make, substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of oil and natural gas reserves.  Historically, the Company has
financed these expenditures primarily with cash generated by operations, bank
borrowings, and the sale of subordinated notes, common stock and preferred
stock.  The Company intends to make aggregate capital expenditures of
approximately $103 million in 1998, including approximately $91 million on the
development and exploitation of its California, Sunniland Trend and Illinois
Basin properties, approximately $6 million on exploration activities primarily
in the Sunniland Trend and approximately $6 million for various other capital
items.  In addition, the Company intends to continue to pursue the acquisition
of underdeveloped producing properties.  The Company believes that it will have
sufficient cash from operating activities and borrowings under the Revolving
Credit Facility to fund such planned capital expenditures.

Changing Oil and Natural Gas Prices

    The Company is affected by changes in crude oil prices which have
historically been volatile.  Although the Company has routinely hedged a
substantial portion of its crude oil production and intends to continue this
practice, substantial future crude oil price declines would have a negative
impact on the Company's overall results, and therefore its liquidity.
Furthermore, low crude oil prices could affect the Company's ability to raise
capital on terms favorable to the Company.  In order to manage its exposure to
commodity price risk, the Company has routinely hedged a portion of its crude
oil production.   For 1998, the Company has entered into various fixed price and
floating price collar arrangements.  Such arrangements generally provide the
Company with downside price protection on approximately 12,250 barrels of oil
per day at a NYMEX Crude Oil Price of approximately $19.80 per barrel.  Thus,
based on the Company's average fourth quarter 1997 crude oil production rate,
these arrangements generally provide the Company with downside price protection
for approximately 60% of its production.  In addition, the Company also has
fixed price  arrangements on 6,000 barrels per day in 1999 at a NYMEX Crude Oil
Price of $18.55 per barrel, or approximately 30% of fourth quarter 1997 crude
oil production levels.   The foregoing NYMEX Crude Oil Prices are before quality
and location differentials.  Management intends to continue to maintain hedging
arrangements for a significant portion of its production.  Such contracts may
expose the Company to the risk of financial loss in certain circumstances.  See
Item 1, "Business--Product Markets and Major Customers".

    Additionally decreases in the prices of oil and natural gas have had, and
could have in the future, an adverse effect on the carrying value of the
Company's proved reserves and the Company's revenues, profitability and cash
flow.  A large portion of the Company's reserve base (approximately 94% of
year-end 1997 reserve volumes) is comprised of long-life oil properties that are
sensitive to crude oil price volatility.  The crude oil price received by the
Company at December 31, 1997, upon which proved reserve volumes, the Present
Value of Proved Reserves and the Standardized Measure as of such date were
based, was $18.34 per barrel.  During the first quarter of 1998, the benchmark
NYMEX crude oil price fluctuated significantly, closing as high as $17.82 per
barrel and as low as $13.21 per barrel.  At March 23, 1998, the benchmark NYMEX
crude oil price was approximately $16.50 per barrel.  Under full cost accounting
rules as prescribed by the SEC, unamortized costs of proved oil and natural gas
properties are subject to a ceiling which limits such costs to the Present Value
of Proved Reserves reduced by future discounted income taxes (the "Standardized
Measure").  At December 31, 1997, the Standardized Measure of the Company's
proved reserves was greater than the book carrying cost of the Company's oil and
gas properties by approximately $85 million.  Subject to ongoing exploitation
and production activities which may affect the estimated volumes and  values of
the Company's 

                                       34
<PAGE>
 
oil and gas properties, the Company estimates that the Standardized Measure of
the Company's proved reserves will approximate the book carrying cost of such
properties at a NYMEX benchmark crude oil price between $15.00 and $16.00 per
barrel and the Company could be required to record a noncash writedown of such
capitalized costs.

Investing Activities

    Net cash flows used in investing activities were $107.6  million, $52.5
million and $64.4 million for the years ended December 31, 1997, 1996 and 1995,
respectively.  Included in such amounts are payments, net of cash received from
property sales and reimbursements from partners, for acquisition, development
and exploration costs of $103.0 million, $49.9 million and $63.9 million for the
same periods, respectively.  Such payments for 1997 and 1995 include $22.0
million and $45.0 million related to the acquisition of the Montebello Field and
the Illinois Basin Properties, respectively.  The Company expended $4.7 million,
$2.6 million and $1.1 million in 1997, 1996 and 1995, respectively, for other
property additions, primarily for surface fee land acquired in connection with
the Montebello Field in 1997,  midstream activities and computer equipment.

Financing Activities

    Net cash provided by financing activities amounted to $78.5 million, $9.9
million and $52.3 million for 1997, 1996 and 1995, respectively.  Aggregate
proceeds from long-term borrowings for these same years were $266.9 million,
$263.7 million and $83.6 million, respectively, while payments of long-term debt
were $207.0 million, $248.1 million and $32.7 million for the respective
periods.  Approximately $25 million borrowed under the Revolving Credit Facility
to fund the acquisition of the Montebello Field and related surface fee land is
included in proceeds from long-term debt in 1997.  Also included in financing
activities during 1997 are net proceeds of approximately $53 million from the
sale of the Series C & D 10.25% Notes and a corresponding payment on the
Revolving Credit Facility.  Financing activities during 1996 include net
proceeds of approximately $144.6 million from the Series A & B 10.25% Notes,
approximately $107 million for the repayment of the 12% Notes, including the 6%
call premium and the net defeasance costs, and approximately $42 million for the
repayment of the Illinois Basin acquisition bridge indebtedness.  The Illinois
Basin acquisition indebtedness of $42 million is included in aggregate financing
proceeds for 1995.  Remaining long-term debt activity is primarily related to
advances received and payments made on the Revolving Credit Facility.  Financing
activities during 1997 include proceeds of $39 million from short-term
borrowings and $21 million of repayments related to crude oil inventory
transactions at the Cushing Terminal.  The short-term borrowings were made under
the Transactional Facility and all inventory acquired has been hedged against
price risk.  Financing activities include proceeds from the sale of capital
stock of $1.1 million, $1.8 million and $.9 million in 1997, 1996 and 1995,
respectively.  Such proceeds  were primarily from the exercise of employee stock
options.

Commitments

    Although the Company obtained environmental studies on its properties in
California, the Sunniland Trend and Illinois Basin, and the Company believes
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 the
Company's 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.  The Company has 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 1997, 1996 and 1995 include $.6 million, $.8 million
and $1.0 million, respectively, of expense associated with these estimated
future costs.  For valuation and realization purposes of the affected 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.

                                       35
<PAGE>
 
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The information required to be provided in this item is included in the
Consolidated Financial Statements of the Company, including the Notes thereto,
attached hereto as pages F-1 to F-25 and such information is incorporated herein
by reference.

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

     There were no disagreements on accounting and financial disclosure with the
Company's independent accountants.

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     Information regarding the directors of the Company will be included in the
proxy statement for the 1998 Annual Meeting of Stockholders (the "Proxy
Statement") to be filed within 120 days after December 31, 1997, and is
incorporated herein by reference.  Information with respect to the Company's
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, if any, regarding beneficial ownership of the Common Stock
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.

                                       36
<PAGE>
 
                                    PART IV

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

  (a) (1)  Financial Statements

           The financial statements filed as part of this report are listed in
           the "Index to Consolidated Financial Statements" on Page F-1 hereof.

      (2)  Exhibits

<TABLE>
 
           <S>        <C>
           2(a)       -   Purchase and Sale Agreement dated October 31, 1995, between Marathon and Crete, as
                          amended by that certain Amendment dated December 4, 1995, among Marathon, Plains
                          Resources Inc. and Plains Illinois Inc. (incorporated by reference to Exhibit 2.1 to
                          Form 8-K dated January 4, 1996).
           2(b)       -   Stock Purchase Agreement dated as of March 15, 1998, among Plains Resources Inc.,
                          Plains All American Inc. and Wingfoot Ventures Seven Inc.
           3(a)       -   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(b)       -   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(c)        -  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).
           4           -  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(a)        -  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(b)       -   Specimen Common Stock Certificate (incorporated by reference to Exhibit 4 to the
                          Company's Form S-1 Registration Statement (Reg. No. 33-33986)).
           4(c)       -   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(d)        -  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).
           10(a)*     -   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(b)*     -   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)).
           10(c)*     -   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)).
</TABLE> 

                                       37
<PAGE>
 
<TABLE> 

           <S>        <C>
           10(d)*     -   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(e)*     -   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(f)      -   Uncommitted Secured Transactional Line of Credit Facility letter agreement dated as of
                          August 23, 1995, between Plains Marketing & Transportation Inc. and The First National
                          Bank of Boston, et al. (incorporated by reference to Exhibit 10(m) of the Company's
                          Annual Report on Form 10-K for the year ended December 31, 1995).
           10(g)      -   Third Amended and Restated Credit Agreement dated as of April 11, 1996 among the
                          Company and ING (U.S.) Capital Corporation, et al. (incorporated by reference to
                          Exhibit 10(n) to the Company's Quarterly Report on Form 10-Q for the quarter ended
                          March 31, 1996).
           10(h)      -   First Amendment to Third Amended and Restated Credit Agreement dated as of December 16,
                          1996, among the Company and ING (U.S.) Capital Corporation, et al. (incorporated by
                          reference to Exhibit 10(i) to the Company's Annual Report on Form 10-K for the year
                          ended December 31, 1996).
           10(i)      -   Amendment dated as of November 22, 1996 to Uncommitted Secured Transactional Line of
                          Credit between Plains Marketing & Transportation Inc. and The First National Bank of
                          Boston, et al. (incorporated by reference to Exhibit 10(j) to the Company's Annual
                          Report on Form 10-K for the year ended December 31, 1996).
           10(j)*     -   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(k)*     -   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(l)*     -   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(m)      -   Second Amendment to Third Amended and Restated Credit Agreement dated as of March 7,
                          1997, among the Company and Internationale Nederlanden (U.S.) Capital Corporation,
                          et.al. (incorporated by reference to Exhibit 10(o) to the Company's Quarterly Report on
                          Form 10-Q for the quarterly period end March 31, 1997).
           10(n)       -  Third Amendment to the Third Amended and Restated Credit Agreement dated as of July 18,
                          1997, among the Company and ING (U.S.) Capital Corporation, et.al. (incorporated by
                          reference to Exhibit 10(a) to the Company's Quarterly Report on Form 10-Q for the
                          quarterly period ended June 30, 1997).
           10(o)       -  Fourth Amendment to the Third Amended and Restated Credit Agreement dated as of August
                          29, 1997, among the Company and ING (U.S.) Capital Corporation, f/k/a Internationale
                          Nederlanden (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
                          September 30, 1997).
           10(p)       -  Fifth Amendment to the Third Amended and Restated Credit Agreement dated as of November
                          3, 1997, among the Company and ING (U.S.) Capital Corporation, f/k/a Internationale
                          Nederlanden (U.S. Capital Corporation, 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, 1997).
           10(q)       -  Fifth Amendment to the Uncommitted Secured Demand Transactional Line of Credit Facility
                          between Plains Marketing & Transportation Inc. and BankBoston, N.A. (f/k/a The First
                          National Bank of Boston) et.al., dated as of August 7, 1997, (incorporated by reference
                          to Exhibit 10(r) to the Company's Quarterly Report on Form 10-Q for the quarterly
                          period ended September 30, 1997).
</TABLE> 

                                       38
<PAGE>
 
<TABLE> 

           <S>        <C>
           10(r)       -  Sixth Amendment to the Uncommitted Secured Demand Transactional Line of Credit Facility
                          between Plains Marketing & Transportation Inc. and BankBoston, N.A. (f/k/a The First
                          National Bank of Boston) et.al., dated as of August 29, 1997, (incorporated by
                          reference to Exhibit 10(t) to the Company's Quarterly Report on Form 10-Q for the
                          quarterly period ended September 30, 1997).
           10(s)*      -  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(t)       -  Seventh Amendment to the Uncommitted Secured Demand Transactional Line of Credit
                          Facility between Plains Marketing & Transportation Inc. and BankBoston, N.A. (f/k/a The
                          First National Bank of Boston) et.al., dated as of November 20, 1997.
           10(u)       -  Eighth Amendment to the Uncommitted Secured Demand Transactional Line of Credit
                          Facility between Plains Marketing & Transportation Inc. and BankBoston, N.A. (f/k/a The
                          First National Bank of Boston) et.al., dated as of January 23, 1998.
           10(v)       -  Sixth Amendment to the Third Amended and Restated Credit Agreement dated as of February
                          10, 1998, among the Company and ING (U.S.) Capital Corporation, f/k/a Internationale
                          Nederlanden (U.S.) Capital Corporation, et.al.
           10(w)       -  Seventh Amendment to the Third Amended and Restated Credit Agreement dated as of March
                          20, 1998, among the Company and ING (U.S.) Capital Corporation, f/k/a Internationale
                          Nederlanden (U.S.) Capital Corporation), et.al.
           21          -  Subsidiaries of the Company.
           23(a)       -  Consent of Price Waterhouse LLP.
           27(a)       -  Financial Data Schedule for the year ended December 31, 1997.
           27(b)       -  Financial Data Schedule for the nine months ended September 30, 1997, restated in accordance with the 
                          provisions of Statement of Financial Accounting Standards No. 128, Earnings Per Share ("SFAS 128").
           27(c)       -  Financial Data Schedule for the six months ended June 30, 1997, restated in accordance with the provisions
                          of SFAS 128.
           27(d)       -  Financial Data Schedule for the three months ended March 31, 1997, restated in accordance with the
                          provisions of SFAS 128.
           27(e)       -  Financial Data Schedule for the year ended December 31, 1996, restated in accordance with the provisions 
                          of SFAS 128.
           27(f)       -  Financial Data Schedule for the nine months ended September 30, 1996, restated in accordance with the 
                          provisions of SFAS 128.
           27(g)       -  Financial Data Schedule for the six months ended June 30, 1996, restated in accordance with the provisions
                          of SFAS 128.
           27(h)       -  Financial Data Schedule for the three months ended March 31, 1996, restated in accordance with the 
                          provisions of SFAS 128.
           27(i)       -  Financial Data Schedule for the year ended December 31, 1995, restated in accordance with the provisions 
                          of SFAS 128.
</TABLE>
---------------
*A management contract or compensation plan.

  (b)  Reports on Form 8-K

  There were no reports on Form 8-K filed during the fourth quarter of 1997.

                                       39
<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: March 26, 1998            By: /s/ Phillip D. Kramer
                                    --------------------------------------------
                                    Phillip D. Kramer, Senior 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: March 26, 1998            By: /s/ Greg L. Armstrong
                                    --------------------------------------------
                                    Greg L. Armstrong, President,
                                    Chief Executive Officer and Director
                                    (Principal Executive Officer)



Date: March 26, 1998            By: /s/ Jerry L. Dees
                                    --------------------------------------------
                                    Jerry L. Dees, Director



Date: March 26, 1998            By: /s/ Tom H. Delimitros
                                    --------------------------------------------
                                    Tom H. Delimitros, Director



Date: March 26, 1998            By: /s/ Cynthia A. Feeback
                                    --------------------------------------------
                                    Cynthia A. Feeback, Controller and Principal
                                    Accounting Officer (Principal Accounting
                                    Officer)



Date: March 26, 1998            By: /s/ William M. Hitchcock
                                    --------------------------------------------
                                    William M. Hitchcock, Director

                                       40
<PAGE>
 
Date: March 26, 1998            By: /s/ Phillip D. Kramer
                                    --------------------------------------------
                                    Phillip D. Kramer, Senior Vice President and
                                    Chief Financial Officer (Principal Financial
                                    Officer)



Date: March 26, 1998            By: /s/ Dan M. Krausse
                                    --------------------------------------------
                                    Dan M. Krausse, Chairman of the Board and
                                    Director



Date: March 26, 1998            By: /s/ John H. Lollar
                                    --------------------------------------------
                                    John H. Lollar, Director



Date: March 26, 1998            By: /s/ Robert V. Sinnott
                                    --------------------------------------------
                                    Robert V. Sinnott, Director



Date: March 26, 1998            By: /s/ J. Taft Symonds
                                    --------------------------------------------
                                    J. Taft Symonds, Director


     The Annual Report to Stockholders of the Company for the year ended
December 31, 1997, 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.

                                       41
<PAGE>
 
                  INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE> 
<CAPTION> 
                                                               PAGE
<S>                                                            <C> 
Plains Resources Inc. and Subsidiaries Consolidated
 Financial Statements:
    Report of Independent Accountants.........................  F-2
    Consolidated Balance Sheets as of December 31, 1997
     and 1996.................................................  F-3
    Consolidated Statements of Income for the years ended
     December 31, 1997, 1996 and 1995.........................  F-4
    Consolidated Statements of Cash Flows for the years
     ended December 31, 1997, 1996 and 1995...................  F-5
    Consolidated Statements of Changes in Stockholders'
     Equity for the years ended December 31, 1997, 1996
     and 1995.................................................  F-6
    Notes to Consolidated Financial Statements................  F-7
</TABLE> 

                                      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, 1997 and 1996, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1997, in conformity with generally accepted
accounting principles.  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 generally accepted auditing standards 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 the opinion expressed above.


PRICE WATERHOUSE LLP

/s/Price Waterhouse

Houston, Texas
February 19, 1998

                                      F-2
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEETS
                       (IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
                                                                                                        DECEMBER 31,
                                                                                               ------------------------------
                                                                                                   1997               1996
                                                                                               -----------         ----------
                                                  ASSETS
<S>                                                                                             <C>                <C>
CURRENT ASSETS
Cash and cash equivalents.................................................................      $   3,714          $   2,517
Accounts receivable.......................................................................         99,597             93,686
Inventory.................................................................................         22,802              4,563
Prepaids and other........................................................................            667              1,092
                                                                                                ---------          ---------
Total current assets......................................................................        126,780            101,858
                                                                                                ---------          ---------

PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method:
   Subject to amortization................................................................        498,038            384,019
   Not subject to amortization............................................................         52,024             41,698
Midstream assets, primarily crude oil terminal and storage facility.......................         35,451             35,122
Other property and equipment..............................................................          8,074              8,275
                                                                                                ---------          ---------
                                                                                                  593,587            469,114
Less allowance for depreciation, depletion and amortization...............................       (180,279)          (158,074)
                                                                                                ---------          ---------
                                                                                                  413,308            311,040
                                                                                                ---------          ---------
OTHER ASSETS..............................................................................         16,731             17,351
                                                                                                ---------          ---------
                                                                                                $ 556,819          $ 430,249
                                                                                                =========          =========
                                     LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
Accounts payable and other current liabilities............................................      $ 102,663          $  93,242
Interest payable..........................................................................          6,601              5,089
Royalties payable and drilling advances...................................................          5,016              7,859
Notes payable and other current obligations...............................................         18,511                511
                                                                                                ---------          ---------
Total current liabilities.................................................................        132,791            106,701

BANK DEBT.................................................................................         80,000             72,700
SUBORDINATED DEBT.........................................................................        202,661            149,121
OTHER LONG-TERM DEBT......................................................................          3,067              3,578
OTHER LONG-TERM LIABILITIES...............................................................          5,107              2,577
                                                                                                ---------          ---------
                                                                                                  423,626            334,677
                                                                                                ---------          ---------
COMMITMENTS AND CONTINGENCIES (NOTE 11)

STOCKHOLDERS' EQUITY
Series D Cumulative Convertible Preferred Stock, $1.00 par value,                                                            
   46,600 shares authorized, issued and outstanding
   at December 31, 1997, net of discount of $2,629,000....................................         20,671                 -- 
Common Stock, $.10 par value, 50,000,000 shares authorized; issued and                                                       
   outstanding 16,703,074 shares at December 31, 1997, and 16,518,645
   shares at December 31, 1996............................................................          1,670              1,652 
Additional paid-in capital................................................................        122,887            120,051
Accumulated deficit.......................................................................        (12,035)           (26,131)
                                                                                                ---------          ---------
                                                                                                  133,193             95,572
                                                                                                ---------          ---------
                                                                                                $ 556,819          $ 430,249
                                                                                                =========          =========
</TABLE>
                See notes to consolidated financial statements.

                                      F-3
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                       CONSOLIDATED STATEMENTS OF INCOME
                     (IN THOUSANDS, EXCEPT PER SHARE DATA)



<TABLE>
<CAPTION>
                                                                                           YEAR ENDED DECEMBER 31,
                                                                                ---------------------------------------------
                                                                                  1997              1996               1995
                                                                                --------          --------           --------
<S>                                                                             <C>               <C>                <C>
REVENUE
Oil and natural gas sales.................................................      $109,403          $ 97,601           $ 64,080
Marketing, transportation and storage.....................................       752,522           531,698            339,826
Interest and other income.................................................           319               309                319
                                                                                --------          --------           --------
                                                                                 862,244           629,608            404,225
                                                                                --------          --------           --------
EXPENSES
Production expenses.......................................................        45,486            38,735             30,256
Purchases, transportation and storage.....................................       740,042           522,167            333,460
General and administrative................................................         8,340             7,729              7,215
Depreciation, depletion and amortization..................................        23,778            21,937             17,036
Interest expense..........................................................        22,012            17,286             13,606
Litigation settlement.....................................................            --             4,000                 --
                                                                                --------          --------           --------
                                                                                 839,658           611,854            401,573
                                                                                --------          --------           --------
Income before income taxes and extraordinary item.........................        22,586            17,754              2,652
Income tax expense (benefit)
   Current................................................................           352                --                 --
   Deferred...............................................................         7,975            (3,898)                --
                                                                                --------          --------           --------
INCOME BEFORE EXTRAORDINARY ITEM..........................................        14,259            21,652              2,652

EXTRAORDINARY ITEM:
   Loss on early extinguishment of debt, net of tax benefit...............            --            (5,104)                --
                                                                                --------          --------           --------
NET INCOME................................................................      $ 14,259          $ 16,548           $  2,652
                                                                                ========          ========           ========

Basic earnings per share:
   Income before extraordinary item.......................................      $   0.85          $   1.32           $   0.19
   Extraordinary item.....................................................             -             (0.31)                 -
                                                                                --------          --------           --------
   Net income.............................................................      $   0.85          $   1.01           $   0.19
                                                                                ========          ========           ========
Diluted earnings per share:
   Income before extraordinary item.......................................      $   0.77          $   1.23           $   0.16
   Extraordinary item.....................................................             -             (0.29)                 -
                                                                                --------          --------           --------
   Net income.............................................................      $   0.77          $   0.94           $   0.16
                                                                                ========          ========           ========
</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,
                                                                                      --------------------------------------
                                                                                        1997            1996         1995
                                                                                      ----------     ---------     ---------
<S>                                                                                   <C>            <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income.........................................................................    $  14,259     $  16,548     $  2,652
Items not affecting cash flows from operating activities:
   Depreciation, depletion and amortization........................................       23,778        21,937       17,036
   Loss on early extinguishment of debt, net of tax................................           --         5,104           --
   Deferred income taxes...........................................................        7,975        (3,898)          --
   Other noncash items.............................................................          221           251           --
Change in assets and liabilities resulting from operating activities:
   Accounts receivable.............................................................       (9,518)      (41,046)     (18,598)
   Inventory.......................................................................      (18,239)          551          405
   Prepaids and other..............................................................          128           (64)         106
   Accounts payable and other current liabilities..................................        9,858        37,296       14,133
   Interest payable................................................................        1,494           977          347
   Royalties payable...............................................................          351         1,352          903
                                                                                       ---------     ---------     --------
Net cash provided by operating activities..........................................       30,307        39,008       16,984
                                                                                       ---------     ---------     --------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash received for the sale of oil and gas properties...............................        2,667         3,066        7,355
Payment for acquisition, exploration and development costs.........................     (105,646)      (53,011)     (71,250)
Payment for additions to other property and assets.................................       (4,655)       (2,551)      (1,120)
Other..............................................................................           --            --          617
                                                                                       ---------     ---------     --------
Net cash used in investing activities..............................................     (107,634)      (52,496)     (64,398)
                                                                                       ---------     ---------     --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt.......................................................      266,905       263,723       83,550
Proceeds from short-term debt......................................................       39,000            --           --
Proceeds from sale of capital stock, options and warrants..........................        1,104         1,785          869
Principal payments of long-term debt...............................................     (207,011)     (248,144)     (32,717)
Principal payments of short-term debt..............................................      (21,000)           --           --
Costs incurred to redeem long-term debt............................................           --        (6,468)          --
Other..............................................................................         (474)       (1,020)         550
                                                                                       ---------     ---------     --------
Net cash provided by financing activities..........................................       78,524         9,876       52,252
                                                                                       ---------     ---------     --------
Net increase (decrease) in cash and cash equivalents...............................        1,197        (3,612)       4,838
Cash and cash equivalents, beginning of year.......................................        2,517         6,129        1,291
                                                                                       ---------     ---------     --------
Cash and cash equivalents, end of year.............................................    $   3,714     $   2,517     $  6,129
                                                                                       =========     =========     ========
</TABLE>

               See notes to consolidated financial statements.

                                      F-5
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES
           CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
                                 (IN THOUSANDS)



<TABLE>
<CAPTION>
                                                         SERIES D           $1.30                                     
                                                        Cumulative        CUMULATIVE                                            
                                                        Convertible       Convertible                                            
                                                      Preferred Stock   Preferred Stock     Common Stock     ADDITIONAL   Accumu-  
                                                      ---------------   ---------------    ---------------    Paid-In      lated   
                                                      SHARES   AMOUNT   SHARES   AMOUNT    SHARES   AMOUNT    Capital     Deficit  
                                                      ------  --------  ------   ------    ------   ------   ---------   --------- 
<S>                                                    <C>   <C>          <C>     <C>      <C>       <C>      <C>         <C>
BALANCE AT DECEMBER 31, 1994.......................     --   $    --        48    $ 481     11,594   $1,159    $ 89,274   $(44,452)
   Preferred stock dividends.......................     --        --        --       --         --       --          --       (879)
   Redemption of $1.30 Cumulative                                                                                                  
      Convertible Preferred Stock..................     --        --       (48)    (481)        --       --          --         -- 
   Conversion of Redeemable Preferred
     Stock.........................................     --        --        --       --      3,628      363      21,406         --
   Issuance of common stock in
      connection with an acquisition...............     --        --        --       --        798       80       6,447         --
   Capital stock issued upon exercise
      of options and other.........................     --        --        --       --        159       16         963         --
   Net income for the year.........................     --        --        --       --         --       --          --      2,652
                                                      ----   -------     -----   ------     ------   ------    --------   --------
BALANCE AT DECEMBER 31, 1995.......................     --        --        --       --     16,179    1,618     118,090    (42,679)
   Capital stock issued upon exercise
      of options and other.........................     --        --        --       --        340       34       1,961         --
   Net income for the year.........................     --        --        --       --         --       --          --     16,548
                                                      ----   -------     -----   ------     ------   ------    --------   --------
BALANCE AT DECEMBER 31, 1996.......................     --        --        --       --     16,519    1,652     120,051    (26,131)
   Capital stock issued upon exercise
      of options and other.........................     --        --        --       --        184       18       1,936         --
   Issuance of preferred stock and warrant
      in connection with an acquisition............     47    20,508        --       --         --       --         900         --
   Dividends on preferred stock....................     --       163        --       --         --       --          --       (163)
   Net income for the year.........................     --        --        --       --         --       --          --     14,259
                                                      ----   -------     -----   ------     ------   ------    --------   --------
BALANCE AT DECEMBER 31, 1997.......................     47   $20,671        --   $  --      16,703   $1,670    $122,887   $(12,035)
                                                      ====   =======     =====   ======     ======   ======    ========   ========
</TABLE>

                                      F-6
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1 -- ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION AND PRESENTATION

     The consolidated financial statements include the accounts of Plains
Resources Inc. (the "Company"), and its wholly-owned subsidiaries.  All material
intercompany accounts and transactions have been eliminated.  Certain
reclassifications have been made to the prior year statements to conform with
the current year presentation.

     The Company is an independent energy company engaged in the acquisition,
exploitation, development, exploration and production of crude oil and natural
gas and the marketing, transportation, terminalling and storage of crude oil.
The Company's upstream oil and natural gas activities are focused in California,
the Sunniland Trend of South Florida (the "Sunniland Trend") and the Illinois
Basin in southern Illinois.  Its midstream marketing activities are concentrated
in Oklahoma, where it owns a two million barrel, above ground crude oil
terminalling and storage facility (the "Cushing Terminal"), Texas, the Gulf
Coast area of Louisiana and California.

     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.  Estimates made by management include: oil and natural gas
reserves, depreciation, depletion and amortization, including future abandonment
costs, income taxes and related valuation allowance and pension 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.

INVENTORY

     Crude oil inventory is 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 a first-in, first-out method.

OIL AND NATURAL GAS PROPERTIES

     The Company follows 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 the Company's 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 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 16).
 

                                      F-7
<PAGE>
 
OTHER PROPERTY AND EQUIPMENT

     Other property and equipment is recorded at cost.  Acquisitions, renewals,
and betterments are capitalized; maintenance and repairs are expensed.
Depreciation on the Cushing Terminal is provided using the straight-line method
over an estimated useful life of forty years; other property and equipment is
also depreciated using the straight-line method over estimated useful lives of
three to seven years.

DEBT ISSUE COSTS

     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.  Debt issue costs, net of accumulated amortization, as of December
31, 1997 and 1996, in the amount of $4.7 million and $5.0 million, respectively,
are included in "Other Assets" in the accompanying Consolidated Balance Sheets.

FEDERAL AND STATE INCOME TAXES

     Income taxes are accounted for in accordance with Statement of Financial
Accounting Standards ("SFAS ") No. 109, Accounting for Income Taxes.  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.

MARKETING, TRANSPORTATION AND STORAGE

     The Company's midstream activities are conducted through various wholly-
owned subsidiaries collectively referred to as ("Plains Marketing"). Plains
Marketing markets principally crude oil of third party producers as well as
crude oil and natural gas produced by the Company. Marketing and transportation
revenue is accrued at the time title to the product sold transfers to the
purchaser and purchases are accrued at the time title to the product purchased
transfers to Plains Marketing. Except for crude oil purchased from time to time
as inventory to service the needs of its terminalling and storage customers, the
Company's policy is to purchase only crude oil for which it has a market and to
structure its sales contracts so that crude oil price fluctuations do not
materially affect the gross margin which it receives.

HEDGING

     The Company utilizes various derivative instruments to hedge its exposure
to price fluctuations on oil and natural gas transactions.  The derivative
instruments used consist primarily of futures and option contracts traded on the
New York Mercantile Exchange ("NYMEX") and crude oil swap contracts entered into
with financial institutions.  These instruments are utilized to hedge
transactions which are based on NYMEX oil and gas prices; therefore, a high
correlation exists between the hedged item and the hedge contract.

     Recognized gains and losses on hedge contracts are reported as a component
of the related transaction.  Results for hedging transactions are reflected in
oil and natural gas sales to the extent related to the Company's oil and natural
gas production and in marketing, transportation and storage revenues to the
extent related to such activities.  Cash flows from hedging activities are
included in operating activities in the Consolidated 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 Accounts Payable and Other in the Consolidated Balance Sheets.
Deferred gains or losses from inventory hedges are included as part of the
inventory cost and recognized when the related inventory is sold.  Crude oil
swap contracts have no carrying value and therefore are not  reflected in the
Consolidated Balance Sheets.

                                      F-8
<PAGE>
 
STOCK OPTIONS

     In October 1995, the Financial Accounting Standards Board ("FASB") issued
Statement No. 123 ("SFAS 123"), Accounting for Stock Based Compensation.  In
accordance with the provisions of SFAS No. 123, the Company applies APB Opinion
25 and related Interpretations in accounting for its stock option plans (See
Note 10).

NOTE 2 -- INVENTORY

     Inventory consists of the following:

                                                       DECEMBER 31,
                                             ------------------------------
                                              1997                   1996
                                             -------                -------
                                                     (IN THOUSANDS)
Crude oil...............................     $18,986                 $2,536
Materials and supplies..................       3,816                  2,027
                                             -------                 ------
                                             $22,802                 $4,563
                                             =======                 ======

     At December 31, 1997, approximately 77% of the crude oil inventory was
hedged with NYMEX futures contracts or short-term physical delivery contracts.
The unhedged inventory is comprised of working inventory and linefill primarily
at the Cushing Terminal.

NOTE 3 -- LONG-TERM DEBT

  Long-term debt consists of the following:
<TABLE>
<CAPTION>
                                                                                                 DECEMBER 31,
                                                                                         ------------------------------
                                                                                           1997                 1996
                                                                                         ---------           ----------
                                                                                                (IN THOUSANDS)
<S>                                                                                      <C>                  <C>
Revolving Credit Facility, bearing interest at weighted average interest                 
 rates of 7.3% and 7.0%, at December 31, 1997 and 1996, respectively................     $ 80,000             $ 72,700 
10.25% Senior Subordinated Notes, due 2006, net of unamortized premium of                 
 $2.7 million and unamortized discount of $.9 million at December 31, 1997
 and 1996, respectively.............................................................      202,661              149,121 
Other long-term debt................................................................        3,578                4,089
                                                                                         --------             --------
Total long-term debt................................................................      286,239              225,910
Less current maturities.............................................................         (511)                (511)
                                                                                         --------             --------
                                                                                         $285,728             $225,399
                                                                                         ========             ========
</TABLE>

REVOLVING CREDIT FACILITY

       The Company has a $165 million revolving credit facility (the "Revolving
Credit Facility") with a group of six banks (the "Lenders"). The Revolving
Credit Facility is guaranteed by all of the Company's subsidiaries except PMTI
Inc. and Plains All American Inc. ("Plains All American") and is secured by the
upstream oil and gas properties of the Company and the guaranteeing subsidiaries
except Plains All American and the stock of all subsidiaries except Plains All
American. The Cushing Terminal is not pledged as security for any of the
Company's debt. The borrowing base under the Revolving Credit Facility at
December 31, 1997, is set at $165 million and is subject to borrowing base
availability as determined 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 oil and natural gas
loans to borrowers similar to the Company. Such borrowing base may be affected
from time to time by the performance of the Company's oil and natural gas
properties and changes in oil and natural gas prices. The Company incurs a
commitment fee of 3/8% per annum on the unused portion of the borrowing base.
The Revolving Credit Facility, as amended, matures on July 1, 1999, at which
time the remaining outstanding balance converts to a term loan which is
repayable in twenty equal quarterly installments commencing October 1, 1999,
with a final maturity of July 1, 2004. The Revolving Credit Facility bears
interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate (as
defined therein). At December 31, 1997, outstanding borrowings under the
Revolving Credit Facility were $80 million. In addition to the amount
outstanding at December 31, 1997, $1 million was reserved against the issuance
of a standby letter of credit.

       The Revolving Credit Facility contains covenants which, among other
things, prohibit the payment of cash dividends, limit the amount of consolidated
debt, limit the Company's ability to make certain loans and investments, and
provide that the Company must maintain a specified relationship between current
assets and current liabilities.

                                      F-9
<PAGE>
 
10.25% SENIOR SUBORDINATED NOTES DUE 2006

       On July 23, 1997, the Company sold $50 million of Senior Subordinated
Notes due 2006, Series C, bearing a stated coupon rate of 10.25% (the "Series C
10.25% Notes").  Such notes were issued pursuant to a Rule 144A private
placement at approximately 107.21% of par to yield a minimum yield to worst of
8.79%, or 9.03% yield to maturity.  On October 30, 1997, the Company exchanged a
total of $49.95 million of the Series C 10.25% Notes for 10.25% Senior
Subordinated Notes due 2006, Series D, (the "Series D 10.25% Notes").  The
Series D 10.25% Notes are substantially identical (including principal amount,
interest rate, maturity and redemption rights) to the Series C 10.25% Notes for
which they were exchanged, except for certain transfer restrictions relating to
the Series C 10.25% notes.  The stated coupon rate of interest and maturity date
of the Series C 10.25% Notes and the Series D 10.25% Notes (collectively, the
"Series C & D 10.25% Notes") are the same as those of the Company's Series A & B
10.25% Notes.  Proceeds from the sale of the Series C & D 10.25% Notes, net of
offering costs, were approximately $53 million and were used to reduce the
balance outstanding on the Revolving Credit Facility.

       On March 19, 1996, the Company sold $150 million of Senior Subordinated
Notes due 2006, Series A, bearing a coupon rate of 10.25% (the "Series A 10.25%
Notes").  Such notes were issued pursuant to a Rule 144A private placement at
approximately 99.38% of the principal amount thereof to yield 10.35%.  On August
8, 1996, the Company exchanged a total of $149.5 million principal amount of the
Series A 10.25% Notes for 10.25% Senior Subordinated Notes due 2006, Series B,
(the "Series B 10.25% Notes").  The Series B 10.25% Notes are substantially
identical (including principal amount, interest rate, maturity and redemption
rights) to the Series A 10.25% Notes for which they were exchanged, except for
certain transfer restrictions relating to the Series A 10.25% Notes.

       Proceeds from the sale of the Series A & B 10.25% Notes, net of offering
costs, were approximately $144.6 million and were used to redeem the Company's
12% Senior Subordinated Notes due 1999 (the "12% Notes") at 106% of the $100
million principal amount outstanding and to retire $42 million of bridge bank
indebtedness which was incurred in December 1995 in connection with the
acquisition of all of the upstream oil and gas assets of Marathon Oil Company
("Marathon") in the Illinois Basin (the "Illinois Basin Properties").  The 12%
Notes were redeemed in April 1996, and the Company recognized an extraordinary
loss of $8.5 million, $5.1 million net of deferred income tax, in connection
therewith.

       The Series A 10.25% Notes, the Series B 10.25% Notes, the Series C 10.25%
Notes and The Series D 10.25% Notes (collectively, the "10.25% Notes") are
redeemable, at the option of the Company, 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.  In addition, prior to March
15, 1999, up to $45 million in principal amount of the Series A & B 10.25% Notes
and up to $15 million in principal amount of the Series C & D 10.25% Notes are
redeemable at the option of the Company, in whole or in part, from time to time,
at 110.25% of the principal amount thereof, with the Net Proceeds of any Public
Equity Offering (as both are defined in the indenture under which the 10.25%
Notes were issued (the "Indenture")).

       The Indenture contains covenants including, but not limited to the
following: (i) limitations on incurrence of additional indebtedness; (ii)
limitations on certain investments; (iii) limitations on restricted payments;
(iv) limitations on dispositions of assets; (v) limitations on dividends and
other payment restrictions affecting subsidiaries; (vi) limitations on
transactions with affiliates; (vii) limitations on liens; and (viii)
restrictions on 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, the Company 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 10.25% Notes are unsecured
general obligations of the Company and are subordinated in right of payment to
all existing and future senior indebtedness of the Company and are guaranteed by
all of the Company's principal subsidiaries.

                                      F-10
<PAGE>
 
OTHER LONG-TERM DEBT

       Included in other long-term debt at December 31, 1997 and 1996 is $3.6
million and $4.1 million, respectively, related to the 1995 acquisition of a
production payment burdening certain of the Company's California properties.
Such other long-term debt has maturities of approximately $.5 million per year
in each of the years 1998 through 2004.

       The aggregate amount of maturities of all long-term indebtedness for the
next five years is:  1998 - $.5 million, 1999 - $4.5 million, 2000 - $16.5
million, 2001 - $16.5 million and 2002 - $16.5 million.

NOTE 4 -- UNCOMMITTED SECURED DEMAND TRANSACTIONAL LINE OF CREDIT FACILITY

       Plains Marketing has a $90 million Uncommitted Secured Demand
Transactional Line of Credit Facility (the "Transactional Facility") with five
banks.  The purpose of the Transactional Facility is to provide standby letters
of credit to support the purchase of crude oil for resale and borrowings to
finance crude oil inventory which has been hedged against future price risk.
The Transactional Facility is secured by all of the assets of Plains Marketing,
primarily accounts receivable and crude oil inventory, and is guaranteed by the
Company.  The Company's guarantee is secured by a $1 million standby letter of
credit issued on behalf of the Company under the Revolving Credit Facility.

       Plains Marketing has established a $25 million sublimit (the "Sublimit")
within the Transactional Facility for borrowings to finance crude oil purchased
in connection with operations at the Cushing Terminal.  Under the terms of the
Sublimit, all purchases of crude oil inventory financed are required to be
hedged against future price risk on terms acceptable to the lenders.  At
December 31, 1997, approximately $37.8 million in letters of credit and $18.0
million in borrowings were outstanding under the Transactional Facility.

       Letters of credit under the Transactional Facility are generally issued
for up to seventy day periods and bear fees of 1 1/8% per annum.  Borrowings
incur interest at the borrower's option of either (i) the Base Rate, as defined,
or (ii) LIBOR plus 1 1/2%.  All financings under the Transactional Facility,
which expires in November 1998, are at the discretion of the lenders.  Aggregate
cash borrowings are limited to $25 million.

NOTE 5 -- CAPITAL STOCK

COMMON STOCK

       The Company has authorized capital stock consisting of 50 million shares
of common stock, $.10 par value, and 2 million shares of preferred stock, $1.00
par value.  At December 31, 1997, there were 16.7 million shares of common stock
("Common Stock") issued and outstanding and 46,600 shares of preferred stock
outstanding. (See Note 18)

STOCK WARRANTS AND OPTIONS

       At December 31, 1997, the Company had warrants outstanding which entitle
the holders thereof to purchase an aggregate one million shares of Common Stock.
Per share exercise prices and expiration dates for the warrants are as follows:
750,000 shares at $6.00 expiring in 1999, 100,000 shares at $7.50 expiring in
2000 and 150,000 shares at $25.00 expiring in 2002.

       The Company has various stock option plans for its employees and
directors (See Note 10).

SERIES D CUMULATIVE CONVERTIBLE PREFERRED STOCK

       In November 1997, the Company issued 46,600 shares of Series D Cumulative
Convertible Preferred Stock (the "Series D Preferred Stock") in connection with
the acquisition of the Arroyo Grande Field (See Note 8).  The Series D Preferred
Stock has an aggregate stated value of $23.3 million and is redeemable at the
Company's 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 

                                      F-11
<PAGE>
 
of $500 and is convertible into Common Stock at a ratio of $25 of stated value
for each share of Common Stock to be issued. Commencing January 1, 2000, the
Series D Preferred Stock will bear an annual dividend of $30 per share. Prior to
such date, no dividends will accrue. 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. This discount will be amortized to retained earnings during the
two year period dividends do not accrue.

$1.30 PREFERRED STOCK

       On October 31, 1995, all outstanding shares of the Company's $1.30
Cumulative Convertible Preferred Stock (the "$1.30 Preferred Stock") were
redeemed for $10 per share plus unpaid and accrued dividends of $.0325 per
share.  The Company paid a total of $496,000, including unpaid dividends, to
redeem the $1.30 Preferred Stock.

REDEEMABLE PREFERRED STOCK

       On January 2, 1995, the Company paid a dividend on its Series C
Cumulative Convertible Preferred Stock (the "Series C Preferred Stock") for the
period of July 14, 1994, through December 31, 1994.  The dividend amount of
approximately $937,000 was paid by issuing additional shares of the Series C
Preferred Stock.  On May 25, 1995, all 209,370 outstanding shares of the Series
C Preferred Stock, including accrued dividends, were converted into
approximately 3.6 million shares of Common Stock.

NOTE 6 -- EARNINGS PER SHARE

       In February 1997, the FASB issued Statement of Financial Accounting
Standards No. 128 ("SFAS 128"), Earnings Per Share ("EPS").  SFAS 128 replaces
the presentation of primary EPS with a presentation of basic EPS and requires a
dual presentation of basic and diluted EPS on the face of the income statement
for all entities with complex capital structures. Basic EPS excludes dilutive
securities and is computed by dividing income available to common stockholders
by the weighted-average number of common shares outstanding for the period.
Diluted EPS reflects the potential dilution that could occur if dilutive
securities were converted into common stock and is computed similarly to fully
diluted EPS pursuant to previous accounting pronouncements.  SFAS 128 is
effective for periods ending after December 15, 1997, and requires restatement
of all prior period EPS data presented.

       The following is a reconciliation of the numerators and the denominators
of the basic and diluted EPS computations for income from continuing operations
for the years ended December 1997, 1996 and 1995, as required by SFAS 128.  All
prior period EPS data has been restated in accordance with the provisions of
SFAS 128.

<TABLE>
<CAPTION>
                                                                          FOR THE YEAR ENDED DECEMBER 31,
                                       ---------------------------------------------------------------------------------------------
                                                     1997                            1996                            1995
                                       ------------------------------   -----------------------------   ----------------------------
                                        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
                                       --------    --------  --------   --------   ---------  -------   ---------  --------  -------
                                                                                 (IN THOUSANDS)
<S>                                      <C>        <C>        <C>       <C>        <C>        <C>       <C>        <C>        <C>
Income before extraordinary item......   $14,259                         $21,652                          $2,652 
Less: preferred stock dividends.......      (163)                             --                             (42)
                                         -------                         -------                          ------                    
Income available to                       
    common stockholders...............    14,096     16,603    $0.85      21,652     16,384    $1.32       2,610     13,859    $0.19
                                                              ======                          ======                          ======

Effect of dilutive securities:
    Employee stock options............        --      1,085                   --        839                   --        396
    Warrants..........................        --        516                   --        421                   --        197
    Series C Preferred Stock..........        --         --                   --         --                   --      1,431
                                         -------     ------              -------     ------               ------     ------         
Income available to common               
    stockholders assuming dilution....   $14,096     18,204    $0.77     $21,652     17,644    $1.23      $2,610     15,883    $0.16
                                         =======     ======   ======     =======     ======   ======      ======     ======   ======

</TABLE>

                                      F-12
<PAGE>
 
     Certain options and warrants to purchase shares of Common Stock were not
included in the computations of diluted EPS because the exercise prices were
greater than the average market price of the Common Stock during the periods of
the EPS calculations, resulting in antidilution.  In addition, the Company's
Series D Preferred Stock, which was issued during 1997, is convertible into
932,000 shares of Common Stock but was not included in the computation of
diluted EPS because the effect was antidilutive.  See Notes 5 and 10 for
additional information concerning outstanding options and warrants.

NOTE 7 -- INCOME TAXES

     The Company's deferred income tax assets (liabilities) at December 31, 1997
and 1996 consist of the tax effect of income tax carryforwards and differences
related to the timing of recognition of certain acquisition, exploration,
exploitation and development costs for financial and tax reporting as follows:

<TABLE>
<CAPTION>
                                                                               DECEMBER 31,
                                                                       -----------------------------
                                                                         1997                1996
U.S. Federal                                                           --------            ---------
------------                                                                  (IN THOUSANDS)
<S>                                                                    <C>                <C>
Deferred tax assets:
  Tax credit carryforwards.......................................      $  1,010            $    934
  Percentage depletion carryforward..............................         2,450               2,450
  Net operating loss ("NOL") carryforwards.......................        60,055              64,186
                                                                       --------            --------
                                                                         63,515              67,570
Deferred tax liabilities:
  Acquisition, exploration and development costs.................       (55,781)            (51,431)
                                                                       --------            --------
  Net deferred tax asset.........................................         7,734              16,139
  Valuation allowance............................................        (6,938)             (8,376)
                                                                       --------            --------
                                                                       $    796            $  7,763
                                                                       ========            ========
States
------
  Deferred tax liability.........................................      $   (958)           $   (462)
                                                                       ========            ========
</TABLE>

      In the first quarter of 1996, the Company reduced its valuation allowance
resulting in the recognition of an $11 million credit to deferred income tax
expense.  The remaining deferred tax asset was not recognized primarily due to
limitations imposed by the IRS regarding the utilization of NOL's generated
prior to certain of the Company's subsidiaries being acquired and the
uncertainty of utilizing the Company's investment tax credit ("ITC")
carryforwards.  While the Company's tax planning strategies address certain of
these restrictions on the application of subsidiary NOL's, management is
currently uncertain as to the extent such strategies will be successful and
therefore concluded that a reserve for these amounts was appropriate.

      At December 31, 1997, the Company had carryforwards of approximately
$171.6 million of regular tax NOL's, $7 million of statutory depletion, $.5
million of ITC and $.5 million of alternative minimum tax ("AMT") credit.  Of
these amounts, utilization of approximately $12.2 million of the NOL
carryforwards and $.4 million of the ITC carryforwards are limited to certain
companies within the consolidated group.  At December 31, 1997, the Company had
approximately $159.2 million of AMT NOL carryforwards available as a deduction
against future AMT income. The NOL carryforwards expire from 1998 through 2011.

      Set forth below is a reconciliation between the income tax provision
computed at the United States statutory rate on income before income taxes and
the income tax provision per the accompanying Consolidated Statements of Income:

<TABLE>
<CAPTION>
                                                                                       YEAR ENDED DECEMBER 31,
                                                                     -------------------------------------------------------
                                                                           1997               1996               1995
                                                                     -----------------  -----------------  -----------------
                                                                                           (IN THOUSANDS)
<S>                                                                         <C>               <C>                 <C>        
U.S. federal income tax provision at statutory rate...............          $7,905            $  6,214            $ 902      
Reduction of valuation allowance against deferred tax asset.......              --             (11,000)              --      
State income taxes................................................             376                 888               --      
Utilization of tax attributes previously included                                                                            
  in allowance and other..........................................              46                  --             (902)     
                                                                            ------            --------            -----      
Income taxes on income before extraordinary item..................           8,327              (3,898)              --      
Income tax benefit allocated to extraordinary item................              --              (3,403)              --      
                                                                            ------            --------            -----      
                                                                            $8,327            $ (7,301)           $  --      
                                                                            ======            ========            =====      
</TABLE>

                                      F-13
<PAGE>
 
      In accordance with certain provisions of the Tax Reform Act of 1986, a
change of greater than 50% of the beneficial ownership of the Company within a
three-year period (an "Ownership Change") will place an annual limitation on the
Company's ability to utilize its existing tax carryforwards.  Under the Final
Treasury Regulations issued by the Internal Revenue Service, the Company does
not believe that an Ownership Change has occurred as of December 31, 1997.

NOTE 8 -- ACQUISITIONS AND DISPOSITIONS

      In March 1997, the Company completed the acquisition of Chevron USA's
("Chevron") interest in the Montebello Field for $25 million, effective February
1, 1997.  The assets acquired consist of a 100% working interest and a 99.2% net
revenue interest in 55 producing oil wells and related facilities and also
include approximately 450 acres of surface fee land.  At the acquisition date,
the Montebello Field, which is located approximately 15 miles from the Company's
existing California operations, was producing approximately 800 barrels of oil
and 800 Mcf of gas per day and added approximately 23 million barrels of oil
equivalent to the Company's proved reserves.  The acquisition was funded with
proceeds from the Revolving Credit Facility.

      On November 12, 1997, the Company acquired a 100% working interest and a
97% net revenue interest in the Arroyo Grande Field in San Luis Obispo County,
California, from subsidiaries of Shell Oil Company ("Shell").  The assets
acquired include surface and development rights to approximately 1,000 acres
included in the 1,500 acre unit.  At the acquisition date, the Arroyo Grande
Field was producing approximately 1,600 barrels of 14 degree API gravity oil
per day from 70 wells and added approximately 20 million barrels of oil
equivalent to the Company's proved reserves.

      The aggregate purchase price of $22.1 million consisted of rights to a
non-producing property interest conveyed to Shell, the issuance of 46,600 shares
of Series D Preferred Stock with an aggregate stated value of $23.3 million and
a 5 year warrant to purchase 150,000 shares of Common Stock at $25 per share.
No proved reserves had been assigned to the rights to the property interest
conveyed.

      On December 22, 1995, Plains Illinois Inc., a wholly owned subsidiary of
the Company, acquired the Illinois Basin Properties, effective November 1, 1995.
The aggregate purchase price was approximately $51.5 million including
associated transaction costs, of which approximately $6.5 million was paid for
by the issuance of 798,143 shares of Common Stock and the remaining $45 million
was paid in cash.  The cash portion of the purchase price was financed through a
combination of advances under the Revolving Credit Facility and $42 million of
bridge bank indebtedness.  The Illinois Basin Properties include three Marathon
operated oil fields, various nonoperated producing properties and all of
Marathon's oil and natural gas mineral interests, surface fee and undeveloped
leasehold within the Illinois Basin as well as Marathon's geological,
geophysical and engineering database for the entire region.  At the acquisition
date, the Illinois Basin Properties added approximately 17.3 million barrels to
the Company's proved oil reserves.

      In December 1995, Stocker Resources Inc. ("Stocker"), a wholly-owned
subsidiary of the Company, acquired from Chevron a production payment burdening
certain of Stocker's California properties.  The production payment had a face
amount of approximately $30 million and was accounted for in prior periods as an
overriding royalty interest.  Stocker also acquired a fifteen year term mineral
interest in certain of its California properties and approximately ten acres of
surface fee land in Los Angeles County.  These assets were acquired in
connection with a settlement agreement resolving certain outstanding issues
between Chevron and Stocker.  In return for the conveyance of the foregoing
assets, Stocker agreed to forgive certain amounts due it, dismiss existing
lawsuits related to such claims and issue to Chevron a ten year note for $4.6
million.  The settlement also provides for a modification of Stocker's existing
contractual obligations to Chevron to plug inactive wells, that Stocker continue
its present activities to remediate oil contaminated soil from existing
wellsites on an accelerated basis, and for the Company to guarantee the
performance of such obligations.

      During 1997, 1996 and 1995, the Company sold certain non-strategic oil and
natural gas properties located primarily in the Gulf Coast areas of Texas and
Louisiana and in Utah for net proceeds of approximately $2.7 million, $3.1
million and $7.4 million, respectively.

                                      F-14
<PAGE>
 
NOTE 9 -- RETIREMENT PLAN

      Effective June 1, 1996, the Company's Board of Directors adopted a
nonqualified retirement plan (the "Plan") for certain officers of the Company.
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, 1997 and 1996, is
comprised of the following components:

<TABLE>
<CAPTION>
                                                                   Year Ended December 31,
                                                                  ------------------------
                                                                   1997             1996
                                                                  ------           -------
<S>                                                                <C>            <C>
                                                                       (IN THOUSANDS)
Service cost - benefits earned during the period...............    $  82           $  44
Interest on projected benefit obligation.......................       60              31
Amortization of prior service cost.............................       37              22
                                                                   -----           -----
Net pension expense............................................    $ 179           $  97
                                                                   =====           =====
</TABLE>

      The following schedule reconciles the status of the Plan with amounts
reported in the Company's balance sheet at December 31, 1997 and 1996.

<TABLE>
<CAPTION>
                                                                                        DECEMBER 31,
                                                                                    --------------------
                                                                                     1997          1996
                                                                                    ------        ------
<S>                                                                                 <C>           <C>
                                                                                      (IN THOUSANDS)
Actuarial present value of benefit obligations:
   Vested benefits..............................................................    $  857         $ 563
   Nonvested benefits...........................................................       184           191
                                                                                    ------         -----
   Accumulated benefit obligation...............................................    $1,041         $ 754
                                                                                    ======         =====
 
   Projected benefit obligation for service rendered to date....................    $1,041         $ 754
   Plan assets at fair value....................................................        --            --
                                                                                    ------         -----
   Projected benefit obligation in excess of plan assets........................     1,041           754
   Unrecognized loss............................................................      (145)           --
   Prior service cost not yet recognized in net periodic pension expense........      (619)         (657)
                                                                                    ------         -----
   Net pension liability........................................................       277            97
   Adjustment required to recognize minimum liability...........................       619           657
                                                                                    ------         -----
   Accrued pension cost liability recognized in the balance sheet...............    $  896         $ 754
                                                                                    ======         =====
</TABLE>

The weighted-average discount rate used in determining the projected benefit
obligation was 7% and 8% for the years ended December 31, 1997 and 1996,
respectively.

NOTE 10 -- STOCK COMPENSATION PLANS

    Historically, the Company has used stock options as a long-term incentive
for its 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 Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees ("APB 25"), no compensation expense has
been recognized in the accompanying financial statements.

    During 1996, the Company's shareholders approved the Company's 1996 Stock
Incentive Plan, under which a maximum of 1.5 million shares of Common Stock were
reserved for issuance. The Company also has options outstanding under its 1991
and 1992 plans, under which a maximum of 2.0 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 the Company's 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.

    In addition, during 1996, the Company granted performance options to
purchase a total of 500,000 shares of Common Stock to two executive officers.
Terms of the options provide for an exercise price of $13.50, the market 

                                      F-15
<PAGE>
 
price on the date of grant, and an exercise period of five years. The
performance options vest when the price of the Common Stock trades at or above
$24 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.

    A summary of the status of the Company's stock options as of December 31,
1997, 1996, and 1995, and changes during the years ending on those dates are
presented below:

<TABLE>
<CAPTION>
                                              1997                     1996                     1995
                                      ----------------------   -----------------------  -----------------------
                                                 WEIGHTED-                WEIGHTED-                WEIGHTED-
                                      SHARES      Average      SHARES      Average      SHARES      Average
            FIXED OPTIONS              (000)   Exercise Price   (000)   Exercise Price   (000)   Exercise Price
           ---------------            ------   --------------  -------  --------------  -------  --------------
<S>                                   <C>      <C>             <C>      <C>             <C>      <C>
Outstanding at beginning of year.....  2,435           $ 8.56   1,728           $ 6.40   1,519            $6.40
Granted..............................    384           $14.33   1,060           $11.34     365            $6.25
Exercised............................   (163)          $ 6.80    (285)          $ 6.26    (147)           $5.92
Forfeited............................    (42)          $ 9.82     (68)          $ 6.63      (9)           $6.68
                                      ------                   ------                   ------
Outstanding at end of year...........  2,614           $ 9.50   2,435           $ 8.56   1,728            $6.40
                                      ======                   ======                   ======
Options exercisable at year-end......  1,494           $ 7.24   1,289           $ 6.78   1,233            $6.40
                                      ======                   ======                   ======
Weighted-average fair value of                                                                 
  options granted during the year....  $4.53                    $3.19                    $2.18 
</TABLE>

  In October 1995, the Financial Accounting Standards Board issued SFAS No. 123,
Accounting for Stock-Based Compensation.  SFAS No. 123 establishes 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 No. 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.  The Company
has elected to follow APB 25 and related Interpretations in accounting for its
employee stock options because, as discussed below, the alternative fair value
accounting provided for under SFAS No. 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 the Company's 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.  The Company will recognize compensation expense under APB 25 in the
future for the two performance options described above, if certain conditions
are met and such options vest.

  Pro forma information regarding net income and EPS is required by SFAS No.123
and has been determined as if the Company had accounted for its 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 1997, 1996
and 1995:  risk-free interest rates of 6.1% for 1997, 6.0% for 1996 and 7.5% for
1995; a volatility factor of the expected market price of the Company's common
stock of .42 for 1997 and .36 for 1996 and 1995; no expected dividends; and
weighted-average expected option lives of 2.6 years in 1997, 2.7 years in 1996
and 3.5 years in 1995.

  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 the Company's 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.

                                      F-16
<PAGE>
 
  For purposes of pro forma disclosures, the estimated fair value of the options
is amortized to expense over the options' vesting period.  Set forth below is a
summary of the Company's net income and EPS as reported and pro forma as if the
fair value based method of accounting defined in SFAS No. 123 had been applied.
The pro forma information is not meant to be representative of the effects on
reported net income 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.

<TABLE>
<CAPTION>
                                                               YEAR ENDED DECEMBER 31,
                              -------------------------------------------------------------------------------------
                                         1997                          1996                          1995
                              --------------------------    -------------------------     -------------------------
                              AS REPORTED     PRO FORMA     AS REPORTED     PRO FORMA     AS REPORTED     PRO FORMA
                              -----------     ----------    -----------     ---------     -----------     ---------
<S>                                <C>            <C>            <C>            <C>            <C>            <C>
Net income (in thousands)...       $14,259        $13,665        $16,548        $16,161         $2,652         $2,497
Basic EPS...................       $  0.85        $  0.81        $  1.01        $  0.99         $ 0.19         $ 0.18
Diluted EPS.................       $  0.77        $  0.74        $  0.94        $  0.92         $ 0.16         $ 0.16
</TABLE>

      The following table summarizes information about stock options outstanding
at December 31, 1997:

<TABLE>
<CAPTION>
                                                    WEIGHTED-                                                      
                                                     Average         WEIGHTED-                                     
                                    NUMBER          Remaining         Average          NUMBER          WEIGHTED-   
                                  Outstanding      Contractual       Exercise        Exercisable        Average   
RANGE OF EXERCISE PRICES          at 12/31/97         Life             PRICE         at 12/31/97    Exercise Price 
------------------------          -----------      -----------       ---------       ------------   --------------
                                                          (SHARE AMOUNTS IN THOUSANDS)
     <S>                           <C>             <C>              <C>              <C>              <C>       
     $ 5.25  to  $ 6.75.........   1,061           4.6 years        $ 6.17            1,022           $ 6.17
     $ 7.50  to  $ 7.81.........     478           5.2 years        $ 7.64              309           $ 7.61
     $10.50  to  $15.63.........   1,075           3.8 years        $13.61              163           $13.26
                                   -----                                              -----
     $ 5.25  to  $15.63.........   2,614           4.4 years        $ 9.50            1,494           $ 7.24
                                   =====                                              =====
</TABLE>

  During 1997 and 1996, pursuant to Board of Directors' resolutions, the Company
contributed approximately 21,000 and 18,000 shares, respectively, of Common
Stock at weighted average prices of $15.22 and $11.35 per share, respectively,
on behalf of participants in the Company's 401(k) Savings Plan, representing a
matching contribution by the Company for 50% of an employee's contribution.

NOTE 11 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION

COMMITMENTS AND CONTINGENCIES

  Minimum commitments in connection with office space and office equipment
leased by the Company are:  1998 - $.8 million; 1999 through 2002 - $.7 million
annually; thereafter - $2.4 million.  Rental payments made under the terms of
similar arrangements totaled approximately $1.1 million in 1997 and in 1996 and
$1.2 million in 1995.

  In connection with its crude oil marketing, Plains Marketing provides certain
purchasers and transporters with irrevocable standby letters of credit to secure
the Company's obligation for the purchase of crude oil (See Note 4).  Generally,
these letters of credit are issued for up to seventy day periods and are
terminated upon completion of each transaction.  At December 31, 1997, Plains
Marketing had outstanding letters of credit of approximately $37.8 million.
Such letters of credit are secured by the crude oil inventory and accounts
receivable of Plains Marketing and are guaranteed by the Company.  To date, no
amounts have been drawn on such letters of credit issued by the Company.

  Under the amended terms of the asset purchase agreement between Stocker and
Chevron, commencing with the year beginning January 1, 2000, and each year
thereafter, Stocker is required to plug and abandon 20% of the then remaining
inactive wells, which currently aggregate approximately 225.  To the extent the
Company elects not to plug and abandon the number of required wells, the Company
is 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, Stocker is 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 Stocker 

                                      F-17
<PAGE>
 
does not expend the required amounts during a calendar year, Stocker is required
to contribute an amount equal to 125% of the actual shortfall to an escrow
account. Stocker may withdraw amounts from such escrow account to the extent it
expends excess amounts in a future year. As of December 31, 1997, Stocker has
not been required to make contributions to an escrow account.

  Although the Company obtained environmental studies on its properties in
California, the Sunniland Trend and the Illinois Basin and the Company believes
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 its California
Properties, Stocker 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.  While the Company
believes that it does not have any material obligations for operations conducted
prior to Stocker's acquisition of the properties from Chevron, other than its
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 it 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 the Company's
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.  The Company has estimated that the costs to perform these tasks is
approximately $11 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 ("DD&A").
Results from operations for 1997, 1996 and 1995 include $.6 million, $.8 million
and $1 million, respectively, of expense associated with these estimated future
costs.  For valuation and realization purposes of the affected 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 16.

  As is common within the industry, the Company has entered into various
commitments and operating agreements related to the exploration and development
of and production from certain proved oil and natural gas properties and the
marketing, terminalling and storage of crude oil.  It is management's belief
that such commitments will be met without a material adverse effect on the
Company's financial position, results of operations or cash flows.

INDUSTRY CONCENTRATION

  Financial instruments which potentially subject the Company to concentrations
of credit risk consist principally of trade receivables.  The Company's accounts
receivable are primarily from purchasers of oil and natural gas products.  This
industry concentration has the potential to impact the Company's 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.
The Company generally requires letters of credit for receivables from customers
which are not considered investment grade, unless the credit risk can otherwise
be mitigated.

  There are a limited number of alternative methods of transportation for the
Company's production.  Substantially all of the Company's California crude oil
and natural gas production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could result in the
Company having to find transportation alternatives, increased transportation
costs to the Company or involuntary curtailment of a significant portion of its
crude oil and natural gas production which could have a negative impact on
future results of operations or cash flows.

NOTE 12 -- LITIGATION

  During 1996, the Company settled two lawsuits filed in 1992 and 1993, relating
to activities in 1991 and 1992, against certain of its officers and directors
for a cash payment of approximately $6.3 million.  Approximately $4.1 million of
such amount was paid by the Company's insurance carrier and $2.2 million was
paid by the Company.  Taking 

                                      F-18
<PAGE>
 
into account prior costs incurred by the Company to defend these suits, and for
which the Company agreed to relinquish its claims for reimbursement against its
insurance company, this settlement resulted in a charge to 1996 first quarter
earnings of $4 million.

  On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in
the United States District Court for the Middle District of Florida, Exxon
Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B.  This action
was filed by Exxon to interplead royalty funds as a result of a title
controversy between certain mineral owners in a field in Florida.  One group of
mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a
counterclaim against Exxon alleging fraud, conspiracy, conversion of funds,
declaratory relief, federal and Florida RICO, breach of contract and accounting,
as well as challenging the validity of certain oil and natural gas leases owned
by Exxon, and seeking exemplary and treble damages.  In March 1993, but
effective November 1, 1992, Calumet Florida, Inc. ("Calumet"), a wholly-owned
subsidiary of the Company, acquired all of Exxon's leases in the field affected
by this lawsuit.  In order to address those counterclaims challenging the
validity of certain oil and natural gas leases, which constitute approximately
10% of the land underlying this unitized field, Calumet filed a motion to join
Exxon as plaintiff in the subject lawsuit, which was granted July 29, 1994.  In
August 1994, the Hughes Group amended its counterclaim to add Calumet as a
counter-defendant.  Exxon and Calumet filed a motion to dismiss the
counterclaims.  On March 22, 1996, the Court granted Exxon's and Calumet's
motion to dismiss the counterclaims alleging fraud, conspiracy, and federal and
Florida RICO violations and challenging the validity of certain of the Company's
oil and natural gas leases but denied such motion as to the counterclaim
alleging conversion of funds.  The Company has reached an agreement in principle
with all parties to settle this case.  In consideration for full and final
settlement, and dismissal with prejudice of all issues in this case, the Company
has agreed to pay to the defendants the total sum of $100,000, and release
certain royalty amounts held in suspense and in the court registry during the
pendency of this case.  Finalization of this settlement has been delayed due to
disputes over certain title issues. Motions have been filed requesting the Court
to rule on the disputes, but no hearing date has been set.  The Company does not
believe that the disputes will adversely affect the settlement reached between
the Company and the defendants.

  The Company, in the ordinary course of business, is a claimant and/or a
defendant in various other legal proceedings in which its exposure, individually
and in the aggregate, is not considered material to the consolidated financial
statements.

NOTE 13 -- MAJOR CUSTOMERS

  Sales to Koch Oil Company ("Koch") and Sempra Energy Trading Corporation
(formerly AIG Trading Corporation) accounted for 27% and 11%, respectively, of
the Company's total revenue (exclusive of interest and other income) during
1997.  Customers accounting for more than 10% of total revenue for 1996 and 1995
were as follows:  1996 -- Koch - 16% and Basis Petroleum, Inc. ("Basis",
formerly Phibro Energy USA, Inc.) - 11%; 1995 -- Phibro Inc. ("Phibro") - 16%
and Basis - 12%.  No other single customer accounted for as much as 10% of total
sales during 1997, 1996 or 1995.  Additionally during 1997, Unocal Energy
Trading, Inc., Marathon Oil Company and Exxon Company U.S.A. accounted for
approximately 52%, 23% and 10%, respectively, of the Company's oil and gas
sales.

NOTE 14 -- FINANCIAL INSTRUMENTS

DERIVATIVES

  The Company has only limited involvement with derivative financial
instruments, as defined in SFAS No. 119, Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments and does not use them for
speculative trading purposes.  The Company's principle objective is to hedge
exposure to price volatility on crude oil and natural gas.  These arrangements
expose the Company to credit risk (as to counterparties) and to risk of adverse
price movements in certain cases where the Company's production is less than
expected.  Substantially all derivatives are either exchange traded or with
major financial institutions and the risk of loss is considered remote.

  The Company has entered into various fixed and floating price collar
arrangements to fix the NYMEX crude oil spot price ("NYMEX Crude Oil Price") for
a significant portion of its crude oil production.  On December 31, 1997, these
arrangements provided for a NYMEX Crude Oil Price for: (i) approximately 12,250
barrels per day from 

                                      F-19
<PAGE>
 
January 1, 1998, through December 31, 1998, at approximately $19.80 per barrel
and (ii) 2,000 barrels per day from January 1, 1999, through December 31, 1999,
at approximately $20.08 per barrel. Since December 31, 1997, the Company has
entered into additional arrangements for 1999, which when combined with
arrangements in effect at December 31, 1997, provide for a NYMEX Crude Oil Price
for approximately 6,000 barrels per day from January 1, 1999, through December
31, 1999, at $18.55 per barrel. Location and quality differentials attributable
to the Company's properties are not included in the foregoing prices. The
agreements provide for monthly settlement based on the differential between the
agreement price and the actual NYMEX Crude Oil Price. Gains or losses are
recognized in the month of related production and are included in oil and
natural gas sales.

FAIR VALUE OF FINANCIAL INSTRUMENTS

  The following disclosure of the estimated fair value of financial instruments
is made in accordance with the requirements of SFAS No. 107, Disclosures About
Fair Value of Financial Instruments.  The estimated fair value amounts have been
determined by the Company using available market information and valuation
methodologies described below.  Considerable judgement 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.

  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 the Company's other financial instruments are as follows:

<TABLE>
<CAPTION>
                                                                                  DECEMBER 31,
                                                          -----------------------------------------------------------
                                                             1997                             1996
                                                           CARRYING          FAIR           CARRYING           FAIR
                                                            Amount           Value           Amount            Value
                                                          ----------       --------        ----------         -------
<S>                                                       <C>              <C>              <C>             <C>
                                                                                 (IN THOUSANDS)
LONG TERM DEBT:
   Bank debt.........................................      $ 80,000         $ 80,000         $ 72,700          $ 72,700
   Subordinated debt.................................       202,661          214,750          149,121           160,500
   Other long-term debt..............................         3,067            3,067            3,578             3,578
OFF BALANCE SHEET FINANCIAL INFORMATION:
   Unrealized gain (loss) on crude oil swap 
     agreements......................................            --            7,246  (1)          --           (15,472)(1)
 
</TABLE> 
--------------- 
(1)  These amounts represent the calculated difference between the NYMEX Crude
     Oil Price and the hedge arrangements for future production of the Company's
     properties as of December 31, 1997 and 1996. Such hedges, and therefore the
     unrealized gains and losses, have been included in estimated future gross
     revenues to arrive at the estimated future net revenues and the
     Standardized Measure disclosed in Note 16.


  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.
Other long-term debt was valued by discounting the future payments using the
Company's incremental borrowing rate.

                                      F-20
<PAGE>
 
NOTE 15 --  SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

  Selected cash payments and noncash activities were as follows:

<TABLE>
<CAPTION>
                                                                           YEAR ENDED DECEMBER 31,
                                                                  -----------------------------------------
                                                                    1997             1996            1995
                                                                  --------         --------        --------
                                                                                (IN THOUSANDS)
<S>                                                               <C>              <C>             <C>
Cash paid for interest (net of amount capitalized)..........      $ 20,486          $16,309         $13,259
                                                                  ========          =======         =======

Noncash investing and financing activities:
   Series D Preferred Stock Dividends.......................      $    163          $    --         $  --
                                                                  ========          =======         =======
   Conversion of Series C Preferred Stock...................      $     --          $    --         $21,769
                                                                  ========          =======         =======
   Tax benefit from exercise of employee stock options......      $    513          $    --         $  --
                                                                  ========          =======         =======

Detail of properties acquired for other than cash:
   Fair value of acquired assets............................      $ 22,140          $    --         $56,100
   Debt issued and liabilities assumed......................            --               --          (4,600)
   Property exchanged.......................................        (1,619)              --              --
   Capital stock and warrants issued........................       (21,408)              --          (6,527)
                                                                  --------         --------         -------
   Cash (received) paid.....................................      $   (887)        $     --         $44,973
                                                                  ========         ========         =======
</TABLE>

NOTE 16 -- OIL AND NATURAL GAS ACTIVITIES

COSTS INCURRED

      The Company's oil and natural gas acquisition, exploration, exploitation
and development activities are conducted in the United States.  The following
table summarizes the costs incurred in connection therewith during the last
three years.

<TABLE>
<CAPTION>
                                                      YEAR ENDED DECEMBER 31,
                                              -----------------------------------------
                                                1997             1996            1995
                                              --------         --------       ---------
                                                          (IN THOUSANDS)
<S>                                           <C>              <C>             <C>
Property acquisition costs:
   Unproved properties..................      $ 15,249          $   728         $18,136
   Proved properties....................        28,182            3,087          41,194
Exploration costs.......................         1,730            2,433           2,001
Exploitation and development costs......        82,217           45,007          22,681
                                              --------          -------         -------
                                              $127,378          $51,255         $84,012
                                              ========          =======         =======
</TABLE>

CAPITALIZED COSTS

     The following table presents the aggregate capitalized costs subject to
amortization relating to the Company's oil and natural gas acquisition,
exploration, exploitation and development activities, and the aggregate related
DD&A.

<TABLE>
<CAPTION>
                                             DECEMBER 31,
                                     ---------------------------
                                        1997              1996
                                     ---------         ---------
                                           (IN THOUSANDS)
<S>                                  <C>               <C>
Proved properties................    $ 498,038         $ 384,019
Accumulated DD&A.................     (171,162)         (150,300)
                                     ---------         ---------
                                     $ 326,876         $ 233,719
                                     =========         =========
</TABLE>

     The DD&A rate per equivalent unit of production was $2.83, $3.00 and $3.02
for the years ended December 31, 1997, 1996 and 1995, respectively.

                                      F-21
<PAGE>
 
COSTS NOT SUBJECT TO AMORTIZATION

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

<TABLE>
<CAPTION>
                                              DECEMBER 31,
                                       ------------------------
                                         1997             1996
                                       -------           ------
                                            (IN THOUSANDS)
<S>                                    <C>               <C>
Acquisition costs..................    $41,652           $31,940
Exploration costs..................      2,573             3,210
Capitalized interest...............      7,799             6,548
                                       -------           -------
                                       $52,024           $41,698
                                       =======           =======
</TABLE>

      Unproved property costs not subject to amortization consist mainly of
acquisition and lease costs and seismic data related to unproved areas.  The
Company 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 37%, 6% and 30% of
the balance in unproved properties at December 31, 1997, related to additions
made in 1997, 1996 and 1995, respectively.

      During 1997, 1996 and 1995, the Company capitalized $3.3 million, $3.6
million and $3.1 million, respectively, of interest related to the costs of
unproved properties in the process of development.

SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)

      The following information summarizes the Company's net proved reserves of
oil (including condensate and natural gas liquids) and natural gas and the
present values thereof for the three years ended December 31, 1997.  The
following reserve information is based upon reports of the independent petroleum
consulting firms of H.J. Gruy and Company and System Technology Associates Inc.
with respect to the Company's California properties, Netherland Sewell &
Associates, Inc. with respect to the Sunniland Trend properties and other minor
properties and Ryder Scott Company with respect to the Illinois Basin
Properties.  The estimates are in accordance with regulations prescribed by the
Securities and Exchange Commission ("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 the control of the Company.  Reserve
engineering is a subjective process of estimating the recovery from underground
accumulations of 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
oil and natural gas that are ultimately recovered, production and operating
costs, the amount and timing of future development expenditures and future 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 oil and
natural gas reserves attributable to the Company's 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.

                                      F-22
<PAGE>
 
ESTIMATED QUANTITIES OF OIL AND NATURAL GAS RESERVES (UNAUDITED)

      The following table sets forth certain data pertaining to the Company's
proved and proved developed reserves for the three years ended December 31,
1997.

<TABLE>
<CAPTION>
                                                             AS OF OR FOR THE YEAR ENDED DECEMBER 31,
                                           ------------------------------------------------------------------------
                                                    1997                      1996                      1995
                                           ----------------------     ---------------------     -------------------
                                              OIL          GAS          OIL          GAS          OIL          GAS
                                             (Bbl)        (Mcf)        (Bbl)        (Mcf)        (Bbl)        (Mcf)
                                           --------      --------     --------     ---------   --------     ---------
<S>                                        <C>          <C>          <C>          <C>          <C>          <C>
                                                                         (IN THOUSANDS)
PROVED RESERVES
   Beginning balance...................      115,996       37,273       94,408       43,110       61,459       51,009
   Revisions of previous estimates.....      (16,091)       3,805       19,424        6,641        5,423        2,792
   Extensions, discoveries, improved                                                                                  
      recovery and other additions.....       17,884        8,126        8,179        1,294       15,489        1,730 
   Sale of reserves in-place...........          (26)        (547)          (5)     (12,491)      (1,227)      (9,773)
   Purchase of reserves in-place.......       40,764       14,566           45          862       17,640          130
   Production..........................       (6,900)      (2,873)      (6,055)      (2,143)      (4,376)      (2,778)
                                             -------       -------     -------      -------      -------       ------- 
   Ending balance......................      151,627       60,350      115,996       37,273       94,408       43,110
                                             =======       ======      =======      =======       ======       ======
PROVED DEVELOPED RESERVES
   Beginning balance...................       86,515       25,629       67,266       29,397       48,978       30,869
                                             =======       ======      =======      =======       ======       ======
   Ending balance......................       99,193       38,233       86,515       25,629       67,266       29,397
                                             =======       ======      =======      =======       ======       ======
</TABLE>
                                        
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

    The Standardized Measure of discounted future net cash flows relating to
proved oil and natural gas reserves is presented below:
<TABLE>
<CAPTION>
                                                           DECEMBER 31,
                                        --------------------------------------------------
                                             1997             1996             1995
                                        --------------   ---------------  ----------------
<S>                                     <C>              <C>              <C>
                                                          (IN THOUSANDS)
Future cash inflows...................     $ 2,237,876       $2,681,007       $1,513,145
Future development costs..............        (157,877)        (111,785)        (107,995)
Future production expense.............      (1,019,254)        (977,551)        (692,008)
Future income tax expense.............        (261,130)        (437,654)        (157,110)
                                           -----------       ----------       ---------- 
Future net cash flows.................         799,615        1,154,017          556,032
Discounted at 10% per year............        (387,792)        (575,436)        (251,191)
                                           -----------       ----------       ---------- 
Standardized measure of                                                                  
   discounted future net cash flows...     $   411,823       $  578,581       $  304,841 
                                           ===========       ==========       ========== 
</TABLE>

      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 the Company's proved properties and the present value thereof
   are made using 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
   received by the Company at December 31, 1997, is based on the NYMEX Crude Oil
   Price of $18.34 per barrel with variations therefrom based on location and
   grade of crude oil.  The Company has entered into various fixed price and
   floating price collar arrangements to fix or limit the NYMEX Crude Oil Price
   for a significant portion of its crude oil production.  Arrangements in
   effect at December 31, 1997, are reflected in the reserve reports through the
   term of the arrangements (See Note 14).  The overall average prices used in
   the reserve reports as of December 31, 1997, were $13.91 per barrel of crude
   oil, condensate and natural gas liquids and $2.13 per Mcf of natural gas.

                                      F-23
<PAGE>
 
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 estimated present value (discounted at 10%) of future
   net revenue from the Company's proved oil and natural gas reserves (the
   "Present Value of Proved Reserves") to be $511.0 million, $764.8 million and
   $366.8 million at December 31, 1997, 1996 and 1995, respectively. SFAS No. 69
   requires the Company to further reduce these estimates by an amount equal to
   the present value of estimated income taxes which might be payable by the
   Company in future years to arrive at the Standardized Measure. Future income
   taxes were calculated by applying the statutory federal income tax rate to
   pretax future net cash flows, net of the tax basis of the properties involved
   and utilization of available tax carryforwards.

     The principal sources of changes in the Standardized Measure of future net
cash flows for the three years ended December 31, 1997, are as follows:

<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,
                                                                           -------------------------------------------
                                                                             1997              1996             1995
                                                                           ---------        ---------        ---------
<S>                                                                        <C>              <C>              <C>
                                                                                          (IN THOUSANDS)
Balance, beginning of year..............................................   $ 578,581        $ 304,841         $202,944
Sales, net of production expenses.......................................     (63,917)         (58,866)         (33,824)
Net change in sales and transfer prices, net of production expenses.....    (359,138)         275,200           26,968
Changes in estimated future development costs...........................       9,927           (5,188)          (3,228)
Extensions, discoveries and improved recovery, net of costs.............      84,676           50,013           59,050
Previously estimated development costs incurred during the year.........      23,449           19,662            3,136
Purchase of reserves in-place...........................................      74,278            2,253           64,214
Sales of reserves in-place..............................................      (1,501)          (3,357)         (11,381)
Revision of quantity estimates..........................................     (57,597)         145,815           24,533
Accretion of discount...................................................      76,477           36,678           22,937
Net change in income taxes..............................................      87,024         (124,254)         (35,512)
Changes in estimated timing of production and other.....................     (40,436)         (64,216)         (14,996)
                                                                           ---------        ---------         --------
Balance, end of year....................................................   $ 411,823        $ 578,581         $304,841
                                                                           =========        =========         ========
</TABLE>

      Decreases in the prices of oil and natural gas have had, and could have in
the future, an adverse effect on the carrying value of the Company's proved
reserves and the Company's revenues, profitability and cash flow.  A large
portion of the Company's reserve base (approximately 94% of  year-end 1997
reserve volumes) is comprised of long-life oil properties that are sensitive to
crude oil price volatility.  The crude oil price received by the Company at
December 31, 1997, upon which proved reserve volumes, the Present Value of
Proved Reserves and the Standardized Measure as of such date were based, was
$18.34 per barrel.  During the first quarter of 1998, the benchmark NYMEX crude
oil price fluctuated significantly, closing as high as $17.82 per barrel and as
low as $13.21 per barrel.  At March 23, 1998, the benchmark NYMEX crude oil
price was approximately $16.50 per barrel.  At December 31, 1997, the
Standardized Measure (See Note 1) of the Company's proved reserves was greater
than the book carrying cost of the Company's oil and gas properties by
approximately $85 million. Subject to ongoing exploitation and production
activities which may affect the estimated volumes and values of the Company's
oil and gas properties, the Company estimates that the Standardized Measure of
the Company's proved reserves will approximate the book carrying cost of such
properties at a NYMEX benchmark crude oil price between $15.00 and $16.00 per
barrel and the Company could be required to record a noncash writedown of such
capitalized costs.

                                      F-24
<PAGE>
 
NOTE 17 -- QUARTERLY FINANCIAL DATA (UNAUDITED)

     The following table shows summary financial data for 1997 and 1996.

<TABLE>
<CAPTION>
                                                                     QUARTER ENDED
                                                 ----------------------------------------------------------             
                                                 MARCH 31         JUNE 30       SEPTEMBER 30    DECEMBER 31
                                                 ---------       ---------     --------------  ------------
<S>                                              <C>              <C>             <C>             <C>
                                                             (IN THOUSANDS, EXCEPT PER SHARE DATA)
1997
Revenues.....................................     $207,132         $188,592        $220,660        $245,860
Operating profits............................     $ 18,609         $ 18,666        $ 18,567        $ 20,874
Net income...................................     $  3,891         $  3,252        $  2,759        $  4,357
Basic EPS....................................     $   0.24         $   0.20        $   0.17        $   0.25
Diluted EPS..................................     $   0.22         $   0.18        $   0.15        $   0.23

1996
Revenues.....................................     $123,513         $155,930        $169,245        $180,920
Operating profits............................     $ 13,360         $ 18,353        $ 17,616        $ 19,377
Income before extraordinary item.............     $  9,216         $  4,614        $  3,486        $  4,336
Net income...................................     $    709         $  6,502        $  5,001        $  4,336
Basic EPS
   Before extraordinary item.................     $   0.57         $   0.28        $   0.21        $   0.26
   Extraordinary item........................        (0.53)            0.12            0.10              --
                                                  --------         --------        --------        --------
                                                  $   0.04         $   0.40        $   0.31        $   0.26
                                                  ========         ========        ========        ========
Diluted EPS
   Before extraordinary item.................     $   0.54         $   0.26        $   0.20        $   0.24
   Extraordinary item........................        (0.50)            0.11            0.08              --
                                                  --------         --------        --------        --------
                                                  $   0.04         $   0.37        $   0.28        $   0.24
                                                  ========         ========        ========        ========
</TABLE>

NOTE 18 -- SUBSEQUENT EVENT -- ALL AMERICAN PIPELINE ACQUISITION (UNAUDITED)

     On March 21, 1998, Plains All American, a wholly owned subsidiary of the
Company, entered into a definitive agreement to acquire 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 The Goodyear Tire & Rubber Company ("Goodyear").
Aggregate proceeds to Goodyear through closing are estimated at $420 million.
The principal assets of the entities to be acquired include the All American
Pipeline System, a 1,233-mile crude oil pipeline extending from California to
Texas, and a 45-mile crude oil gathering system in the San Joaquin Valley of
California, as well as other assets related to such operations. The purchase
price is subject to certain adjustments through the closing date, and the
transaction is subject to regulatory review and approval. The transaction is
expected to be completed in the third quarter of 1998 after regulatory approvals
by the United States Department of Justice and the Federal Trade Commission
under the Hart-Scott-Rodino Anti-Trust Improvements Act of 1976, as amended, and
by the Public Utilities Commission of the State of California have been secured.
For 1997, the operations to be acquired generated approximately $65 million in
earnings before interest, taxes, depreciation and amortization.

     A major portion of the financing for the transaction will be provided
through a new $325 million, limited recourse bank facility made available to
Plains All American by ING Barings and BankBoston N.A. In addition to the bank
facility, the Company will make a capital contribution to Plains All American of
up to $130 million which will be used to fund the balance of the purchase price
and transaction costs and provide initial working capital. To finance its
capital contribution, the Company will borrow approximately $50 million under
the Revolving Credit Facility and has entered into financing commitments for a
new issue of privately placed, convertible preferred stock aggregating
approximately $80 million. Commitments for the preferred stock placement have
been obtained from a group of equity investors comprised primarily of existing
shareholders. The preferred stock has an aggregate stated value of $80 million
and bears a cumulative dividend of 9.5% per annum, payable semi-annually in
either cash or additional shares of preferred stock at the Company's option.
Each share of preferred stock is convertible into 27.78 shares of Common Stock
(an effective conversion price of $18.00 per share) and in certain circumstances
may be converted at the Company's 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. The preferred stock is redeemable at the option of the Company
at 110% of stated value after March 31, 1999 and at declining amounts
thereafter. If not previously redeemed or converted, the preferred stock is
required to be redeemed in 2012.

                                      F-25