<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, 1995

[ ]  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)

           1600 Smith Street
            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:
  Title of each class:                Name of each exchange on which registered:
     Common Stock, par value $.10 per share    American Stock Exchange
     12% Senior Subordinated Notes due 1999    American Stock Exchange

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
$137,025,000 on February 26, 1996 (based on $8 3/4 per share, the last sale
price of the Common Stock as reported on the American Stock Exchange Composite
Tape on such date).

16,182,420 shares of the registrant's Common Stock were outstanding as of
February 26, 1996.

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]

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<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 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 the Los Angeles Basin of California (the "LA
Basin"), the Sunniland Trend of South Florida (the "Sunniland Trend"), the
Illinois Basin and the Gulf Coast area of Louisiana. The Company's downstream
marketing activities are concentrated in Oklahoma, where it owns a two million
barrel, above ground crude oil terminalling and storage facility, Texas and the
Gulf Coast area of Louisiana. The Company's upstream operations contributed
approximately 90% of the Company's 1995 EBITDA proforma for the Illinois Basin
Acquisition, while the Company's downstream activities accounted for the
remainder. 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 business strategy is to increase its proved reserves and cash
flow by exploiting and producing oil and natural gas from its existing
properties, acquiring additional underdeveloped oil properties and exploring for
significant new sources of reserves.  The Company concentrates its exploitation
efforts on mature but underdeveloped crude oil producing properties in areas
that meet the Company's targeted criteria.  Generally, such properties were
previously owned by major integrated oil and gas companies or large independent
oil and gas companies.  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
efforts is to increase unit operating margins, and therefore cash flow, by
reducing unit production expenses and increasing wellhead price realizations.
The Company also seeks to capitalize on downstream opportunities that complement
its oil producing activities.  The Company's marketing of its crude oil
production takes advantage of the marketing expertise and economies of scale
attributable to its downstream activities.  As part of its business strategy,
the Company periodically evaluates, and from time to time has elected to sell,
certain of its fully developed producing properties.  Such sales enable the
Company to maintain financial flexibility, control overhead and redeploy the
sales proceeds to activities that have potentially higher financial returns.

     During the five-year period ended December 31, 1995, the Company incurred
aggregate acquisition, exploration, development and exploitation costs of
approximately $287 million, resulting in proved oil and natural gas reserve
additions (including revisions of estimates but excluding production) of
approximately 112.8 million BOE, or $2.55 per BOE, through implementation of its
business strategy.  See Item 2, "Properties--Oil and Natural Gas Reserves".
Approximately 82% of these expenditures were directed toward the acquisition,
exploitation and development of proved reserves while approximately 18% were
incurred on exploration activities.

     On December 22, 1995, the Company acquired all of Marathon Oil Company's
("Marathon") upstream oil and gas assets in the Illinois Basin (the "Illinois
Basin Properties").  The acquisition of the Illinois Basin Properties (the
"Illinois Basin Acquisition") was effective as of November 1, 1995.  As a result
of such acquisition,

----------------------
/(1)/  As used in this Report, "Mcf" means thousand cubic feet, "Bcf" means
       billion cubic feet, "Bbl" means barrel, "MBbls" means thousand barrels,
       "MMBbls" means million barrels, "Btus" means British Thermal Units,
       "MBtus" means thousand Btus, "MMBtus" means million Btus, "BOE" means
       barrels of oil equivalent, and "MMBOE" means million BOE. Natural gas is
       converted to BOE 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 a working interest is owned. The number of "net acres" is the
       sum of fractional working interests owned in gross acres. "Net" oil and
       gas wells are obtained by multiplying "gross" oil and 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 net cash flows (before income taxes) of proved oil and
       natural gas reserves based on product prices in effect on the date of
       determination. "EBITDA" means earnings before interest, taxes, 
       depreciation, depletion and amortization.

                                       1
<PAGE>
 
the Company added approximately 17.3 million barrels of oil to its proved
reserve base at an aggregate cost of approximately $51.5 million, or an average
of $2.98 per BOE ($0.50 per MCFE).  The Company intends to aggressively exploit
these properties to evaluate additional reserve potential identified during its
acquisition analysis.  In addition, the Company's exploitation plan for the
Illinois Basin Properties targets improving the unit gross margin by decreasing
unit production expenses and increasing price realizations as well as increasing
production volumes by conducting production enhancement activities similar to
those employed in its LA Basin Properties and Sunniland Trend Properties.

     In order to manage its exposure to commodity price risk, the Company has
routinely hedged a portion of its crude oil production.  For 1996, the Company
has committed an average of approximately 8,500 Bbls of oil per day to fixed
price arrangements that expire at various times throughout 1996.  Such
arrangements represent approximately 55% of the Company's average daily oil
production for 1995 pro forma for the Illinois Basin Acquisition and partially
mitigate the adverse impact of potential oil price declines on the Company's
operating results.

     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 " Commission"), 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,
                                         ----------------------------------------------------                                    
                                           1991      1992      1993(1)    1994         1995
                                         -------   --------   --------  --------     --------
                                          (IN THOUSANDS, EXCEPT RATIOS AND PER UNIT AMOUNTS)
<S>                                      <C>       <C>        <C>       <C>          <C>
Present Value of Proved Reserves.......  $71,718   $155,360   $134,539  $229,371     $366,780
 
Proved Reserves
 Crude oil and natural gas
  liquids (Bbls).......................    6,576     33,390     38,810    61,459      94,408
 Natural gas (Mcf).....................   42,898     39,861     49,397    51,009      43,110
 Oil equivalent (BOE)..................   13,726     40,034     47,043    69,960     101,593
 
Reserve Replacement Ratio(2)...........      530%     1,100%       270%      620%        647%(3)
 
Reserve Replacement Cost per BOE(4)....  $  5.86   $   2.35   $   5.39  $   1.49     $  2.14
 
Total upstream capital costs incurred..  $32,256   $ 68,209   $ 61,769  $ 40,849     $84,012
Percentage of total upstream capital
 costs attributable to:  
 Acquisition...........................       30%        56%        40%       48%         71%
 Development...........................       23%        17%        43%       38%         27%
 Exploration...........................       47%        27%        17%       14%          2%
West Texas Intermediate ("WTI") crude
oil posted price at December 31,.......  $ 17.75   $  18.00   $  12.50  $  16.00     $ 18.00
</TABLE>

--------------------
(1) A large portion of the Company's reserve base is comprised of long-life oil
    properties that are sensitive to low crude oil prices.  During the fourth
    quarter of 1993, crude oil prices declined significantly, with the posted
    price for WTI crude oil ending the year at $12.50 per Bbl, the lowest year-
    end oil price in the 13 years since U. S. crude oil prices were deregulated.
    Such low prices had an adverse affect on the proved reserves and Present
    Value of Proved Reserves at December 31, 1993, and led to a noncash charge
    of $20 million related to a writedown of the capitalized costs of the
    Company's proved oil and natural gas properties.

                                       2
<PAGE>
 
(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 effects of
    revisions, if any, ("Reserve Additions") by (b) each respective year's
    production. Reserve information at each year end is based on reports
    prepared by independent petroleum engineers.
(3) Pro forma as if the Illinois Basin Acquisition occurred on January 1, 1995.
(4) Reserve Replacement Cost per BOE for a year is calculated by dividing
    capital expenditures 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
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
enhancements.  After the initial acquisition, the Company also seeks 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 modifying production practices, realigning existing waterflood patterns,
drilling wells and performing workovers, recompletions and other production
enhancements, the Company seeks to offset normal production declines, replace
its annual production volumes and expand its reserve base.  The results of such
activities are reflected in additions and revisions to proved reserves.  During
the four year period ending December 31, 1995, net additions and revisions to
proved reserves totaled 48.6 million BOE or approximately 300% of cumulative net
production for such period.  Such reserves were added at an aggregate average
cost of $2.33 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 58.6 million BOE and were added at an
aggregate average cost of $2.41 per BOE.

     The Company's properties in its three core areas represent approximately
96% of total reserves at December 31, 1995.  Such properties were previously
owned and operated by major integrated oil and gas companies and are comprised
of underdeveloped crude oil properties believed by the Company to have
significant

                                       3
<PAGE>
 
upside potential that can be evaluated through development and exploitation
activities.  During 1996, the Company estimates it will spend approximately $40
million on the development and exploitation of its LA Basin, Sunniland Trend and
Illinois Basin Properties. Set forth below is a discussion of such properties:

   Current Exploitation Projects

     Los Angeles Basin Properties.  Prior to its acquisition by the Company in
     -----------------------------                                            
May 1992, Stocker Resources, Inc. ("Stocker") was a sole purpose company formed
in 1990 to acquire substantially all of Chevron U.S.A.'s ("Chevron") producing
oil properties in the LA Basin.  The aggregate purchase price paid by the
Company for Stocker was approximately $23 million and consisted of (i) $14
million cash; (ii) 400,000 shares of its common stock ("Common Stock") valued at
$6.8 million; (iii) warrants to purchase an aggregate 150,000 shares of Common
Stock valued at $.5 million; and (iv) associated transaction costs.  Following
the initial acquisition, the Company expanded its holdings in this area by
acquiring additional interests within the existing fields.  In late 1993, the
Company acquired all of Texaco Exploration and Production, Inc.'s ("Texaco")
interest in the Vickers Lease for approximately $5 million.  The Vickers Lease
is located immediately adjacent to one of the Company's existing properties and
was consolidated into Stocker's existing operations.  All of the Company's oil
properties in the LA Basin are collectively referred to in this Report 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,
1995, the LA Basin Properties have produced over 400 million barrels of oil and
350 Bcf of natural gas.  Since mid-1992, 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 6,650 BOE per day in May
1992 to an average of 8,400 BOE per day during 1995.

     The Company has expended approximately $64.4 million in direct acquisition,
development and exploitation capital on the LA Basin Properties.  From the
effective dates of acquisition through December 31, 1995, net production from
such properties totaled 11.1 million BOE, generating cumulative net margin (oil
and gas revenue less production expenses) and proceeds from minor property sales
of approximately $78.9 million.  Total estimated proved reserves attributable to
the LA Basin Properties have increased from 17.7 million BOE at initial
acquisition to approximately 60.6 million BOE at December 31, 1995.  Estimated
future net revenues and the Present Value of Proved Reserves at December 31,
1995, were estimated at $483.9 million and $220.8 million, respectively.  As a
result, the Company's aggregate reserve addition cost to date for the LA Basin
Properties is approximately $.90 per BOE.  During 1995, the unit gross margin
for this area averaged $7.74 per BOE.  During 1996, the Company estimates it
will spend approximately $16 million on the further development and exploitation
of the LA Basin Properties.

     South Florida Sunniland Trend Properties.  During the first quarter of
     ----------------------------------------                              
1993, the Company acquired all of the capital stock of Calumet Florida, Inc.
("CFI") for approximately $5 million.  CFI was organized in February 1993 to
purchase and operate a 50% working interest in six producing fields located in
the Sunniland Trend previously owned and operated by Exxon Corporation
("Exxon").  During 1994, CFI 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 in this Report 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 88 million barrels of oil through
December 31, 1995.  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
exploitation activities designed primarily to repair failed wells and to
increase the fluid lift capacity of certain wells and the acquisition

                                       4
<PAGE>
 
of the remaining 50% working interest, the Company's net production averaged
3,400 barrels of oil per day during 1995.

     The Company has expended approximately $33.1 million in direct acquisition,
development and exploitation capital on the Sunniland Trend Properties.  From
the effective dates of acquisition through December 31, 1995, net production
from such properties totaled 2.7 million BOE, generating cumulative net margin
of approximately $17 million.  Total estimated proved reserves attributable to
the Sunniland Trend Properties have increased from approximately 5 million BOE
at initial acquisition to approximately 20 million BOE at December 31, 1995.  At
December 31, 1995, estimated future net revenues and the Present Value of Proved
Reserves were estimated at $89 million and $72 million, respectively. As a
result, the Company's aggregate reserve addition cost to date for the Sunniland
Trend Properties is approximately $1.46 per BOE.  During 1995, the unit gross
margin for this area averaged $5.88 per BOE.  During 1996, the Company estimates
it will spend approximately $18 million on the further development and
exploitation of the Sunniland Trend Properties.  See "-- Exploration -- Current
Exploration Projects -- South Florida Sunniland Trend".

     Illinois Basin Properties.  In December 1995, the Company acquired all of
     -------------------------                                                
Marathon's producing and nonproducing upstream oil and gas assets in the
Illinois Basin.  This acquisition was effective as of November 1, 1995.  As a
result of such acquisition, the Company added approximately 17.3 million barrels
of oil to its proved reserve base at an aggregate average cost of $2.98 per BOE.
The aggregate purchase price, including associated closing costs, was $51.5
million, comprised of 798,143 shares of the Company's 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
Acquisition Indebtedness").  The Illinois Basin Properties consist of long-life
oil reserves.  The largest of the three fields was discovered in 1905 and has
produced over 400 million barrels of oil through December 31, 1995.

     The Company intends to aggressively exploit these properties to evaluate
additional reserve potential identified during its acquisition analysis.  The
Company's exploitation plan for the Illinois Basin Properties involves improving
the unit gross margin by decreasing unit production expenses and increasing
price realizations as well as increasing production volumes by conducting
production enhancement activities similar to those employed in its LA Basin
Properties and Sunniland Trend Properties.  At December 31, 1995, estimated
proved reserve volumes totaled approximately 17.1 million BOE and estimated
future net revenues and the Present Value of Proved Reserves were estimated at
$122 million and $66 million, respectively.  Production for the two month period
included in the Company's 1995 results totaled approximately 224,000 BOE.  Under
Marathon's operations during 1995, the unit gross margin for this property
averaged $6.75 per BOE.  During 1996, the Company estimates it will spend
approximately $6 million implementing its exploitation plan on the Illinois
Basin Properties.

     The Company believes that its properties in its three core areas hold
potential for additional increases in production, reserves and cash flow.
However, there can be no assurance that such increases will be achieved.

     The Company believes that attractive acquisition opportunities 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 continuously
evaluating acquisition opportunities, there can be no assurance that any of
these efforts will be successful.  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.

                                       5
<PAGE>
 
EXPLORATION

  Exploration Strategy

     The Company seeks to complement its strategy of acquiring and exploiting
mature but underdeveloped 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 February 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 opportunities that are
candidates for the application of 3-D seismic technology.  The joint venture
covers exploration activities in the Sunniland Trend, the Illinois Basin and the
LA Basin as well as the Company's current 3-D seismic project at the Four Isle
Dome Field in Terrebonne Parish, Louisiana.  3DX will be responsible for the
geological and geophysical oversight and project technical management of such
projects.  In connection with the joint venture, 3DX acquired 15% to 20% of the
Company's working interests in certain projects, excluding designated productive
areas within each field.  3DX will have the right to participate for up to 20%
in the Company's new exploration and exploitation projects.

  Current Exploration Projects

     South Florida Sunniland Trend.  During 1995, the Company completed a multi-
     ------------------------------                                            
year study of the exploration potential of the Sunniland Trend.  Using recent
advancements in seismic technology, the Company has identified several prospects
that are analogous to the existing producing fields in this trend. The Company
also formed a long-term, 50/50 joint venture with Meridian Oil Company to
conduct exploration activities in the Sunniland Trend.  As a result of the 3DX
joint venture, the Company's net share of this project may be reduced to 42% if
certain events occur.  The Company is the operator of this joint venture and
intends to drill one exploratory well in this area during 1996.  See "--
Acquisition and Exploitation--Current Exploitation Projects--South Florida
Sunniland Trend Properties".

     Four Isle Dome.  The Company, Phillips Petroleum Company ("Phillips") and
     ---------------                                                          
Nuevo Energy Company ("Nuevo") entered into an agreement to explore
approximately 20,000 acres in Terrebonne Parish, Louisiana currently held under
seismic option.  During 1995, the joint venture conducted a 3-D seismic survey
covering approximately 52 square miles.  The area, known as Four Isle Dome, was
discovered in 1934 and has produced to date over 540 Bcf of natural gas and 20
million Bbls of oil.  The Company, Phillips and Nuevo each hold a 33.3% interest
in the project which is subject to a proportionate 25% reduction if the mineral
owner, Louisiana Land and Exploration ("LL&E"), elects to participate in a given
prospect.  In such instance, the Company, Nuevo, Phillips and LL&E would each
hold a 25% working interest.  As a result of the 3DX joint venture, the
Company's net share of this project was reduced to 27% (20% if LL&E
participates).  The Company is the operator of the joint venture and intends to
drill up to two wells in this project during 1996.

     1995 Domestic and International Exploration Activities.  The Company's 1995
     -------------------------------------------------------                    
exploration efforts were concentrated on the drilling of a well in its Miami Fee
prospect in Cameron Parish, Louisiana and the geophysical and geological work
necessary to prepare for drilling evaluations on the two projects discussed
above.  The Company's drilling efforts in the Miami Fee prospect validated the
geophysical concept of the Miami Fee prospect, but did not result in a
discovery.  Because of the disproportionate cost sharing arrangements entered
into with its partners, the Company did not incur any net cost in 1995 in the
drilling of this prospect.  The Company's ownership in the Miami Fee prospect is
subject to the 3DX joint venture; however, no capital expenditures are planned
for this prospect in 1996.

                                       6
<PAGE>
 
     Since late 1991, the Company has focused its international efforts on
generating high-potential exploration opportunities that can be sold to larger
companies, retaining a small but meaningful carried interest in such high
potential opportunities.  The Company has successfully implemented this
strategy, causing two high potential wells to be drilled in Peru; however, such
activities did not result in a discovery.  The Company currently has interests
in two exploratory permits in Australia covering approximately 404,000 gross
(304,000 net) acres, one exploration license in New Caledonia covering 143,000
gross (10,725 net) acres and an exclusive exploration reconnaissance permit in
Pakistan covering 7.7 million net acres. In connection with its joint venture
and strategic alliance with 3DX, the Company has decided not to generate new
international exploration opportunities.  In addition, during 1996 the Company
intends to wind up its current international exploration opportunities by
selling off a majority of its interest in these projects and retaining a carried
interest in any subsequent drilling activity or selling the international
subsidiary.

     During 1996, the Company estimates it will spend approximately $5 million,
net of partner reimbursements, on exploration activities, primarily in Four Isle
Dome and 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 exploitation and development
activities.  There can be no assurance that any of the Company's current
exploration projects will result in proved reserves or commercially viable oil
or natural gas production being obtained.

     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.

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 maintain
financial flexibility, reduce overhead and redeploy the proceeds therefrom to
activities that the Company believes potentially have a higher financial return.
During 1995, the Company sold non-strategic oil and natural gas properties
located primarily in the Gulf Coast area of Texas and Louisiana for aggregate
proceeds of $7.4 million.  As a result, approximately 96% of the Company's 1995
year-end proved reserve volumes and proved reserve value were associated with
its properties in the LA Basin, Sunniland Trend and Illinois Basin.

DOWNSTREAM ACTIVITIES

     The Company's marketing effort entails purchasing crude oil from producers
and marketing it to the refining sector.  The Company aggregates these volumes
at major crude oil interchanges and trading locations and is therefore able to
obtain higher prices for its own production while realizing profits on the
production purchased from others.  The Company owns and operates a two million
barrel, above ground crude oil storage and terminalling facility in Cushing,
Oklahoma (the "Cushing Terminal"), the United States' largest inland crude oil
interchange and trading location.  This facility enhances the competitive
marketing ability of the Company by enabling it to take crude oil from different
sources and make physical delivery of crude oil in Cushing, the NYMEX designated
delivery location.  This facility also enables the Company to aggregate crude
oil volumes and to segregate, store, terminal and provide contract services for
its customers.  The Company's downstream activities have expanded significantly
over the last four years, with gross margin increasing from $1.2 million in 1991
to $6.4 million in 1995.  Based on additional capacity available at the Cushing
Terminal, the Company believes it can increase its downstream gross margin
without expending substantial additional capital.

     Crude oil is purchased at the wellhead and transported by Company-owned
trucks or third-party transporters to a trading location where the Company sells
the crude oil to a refiner or other purchaser.  The Company also purchases crude
oil in the spot market at trading locations.  The Company's policy is to only
purchase crude oil for

                                       7
<PAGE>
 
which it has a market to sell and to negotiate its sales contracts so that crude
oil price fluctuations do not 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 maintained a gross margin of approximately 2%
in its marketing activities for each of the years 1992 through 1995.  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 Cushing Terminal was completed in December 1993.  The facility consists
of two million barrels of above ground shell storage capacity.  The Cushing
Terminal was built at a total cost of approximately $30.9 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 Company's Cushing storage facility was constructed 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.  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 $7.50 to $8.00 per Bbl of shell
capacity.  The Company generates revenue from the Cushing Terminal through a
combination of storage, reservation and throughput fees from customers such as
(i) refiners and gatherers seeking to segregate or custom blend crudes for
refining feedstocks, (ii) pipelines requiring segregated tankage for foreign
cargoes, (iii) traders who make or take delivery under the NYMEX contract, (iv)
producers seeking to increase their marketing alternatives and (v) contango
market crude oil trading activities.

     The Company's upstream and downstream business segments focus on crude oil
as the primary product.  As a result of inefficiencies inherent in the crude oil
market and the U.S. pipeline and transportation infrastructure, management
believes its competitive abilities are enhanced by the alternatives afforded it
by its proprietary access to the Cushing Terminal.  Such alternatives include
the ability to take and make physical delivery of crude oil in Cushing, the
NYMEX designated delivery location.  The Company's crude oil marketing expertise
further provides it with a competitive advantage in obtaining higher prices for
the Company's existing production and identifying potential crude oil price
enhancements for properties targeted for acquisition.

                                       8
<PAGE>
 
OPERATING ACTIVITIES

     The following table presents certain information with respect to the
Company's oil and natural gas producing, marketing, transportation and storage
activities during the three years ended December 31, 1993, 1994 and 1995:

<TABLE>
<CAPTION>
                                                 YEAR ENDED DECEMBER 31,
                                               ---------------------------
                                                 1993     1994      1995
                                               --------  --------  -------
                                                    (IN THOUSANDS)
<S>                                            <C>       <C>       <C> 
Sales to unaffiliated customers:
  Oil and natural gas........................  $ 57,507  $ 57,234   $ 64,080
  Marketing, transportation and storage......   128,186   199,239    339,826
 
Operating profits:
  Oil and natural gas (1)....................  $ 29,519  $ 30,122   $ 34,029
  Marketing, transportation and storage (2)..     3,834     6,305      6,480
 
Identifiable assets:
  Oil and natural gas........................  $180,209  $204,778   $271,248
  Marketing, transportation and storage......    56,458    62,126     80,798
</TABLE>
-------------
(1) Consists of primarily oil and natural gas sales less production expenses.
(2) Consists of primarily marketing, transportation and storage sales less
    purchases and transportation and storage expenses. Includes approximately
    $337,000, $1.5 million and $121,000 during 1993, 1994 and 1995,
    respectively, of operating profit attributed to contango market
    transactions.

     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 oil and natural gas
purchased for resale is higher, as a percentage of sales price, than the
Company's cost of oil and natural gas produced.  See "--Downstream Activities".

GENERAL

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

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 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.

     In order to partially mitigate the adverse affects of crude oil price
volatility, the Company routinely commits a significant portion of its crude oil
production, its principal product, to fixed price contracts or other hedging
arrangements.  To ensure a fixed price for future production, the Company may
sell a futures contract and

                                       9
<PAGE>
 
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 & Transportation Inc. ("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.  

     At December 31, 1995, the Company's financial hedge arrangements
provided for a benchmark NYMEX WTI indexed average price for:  (i) 11,000
barrels per day through March 31, 1996, at $18.07 per barrel; (ii) 10,000
barrels per day from April 1, 1996, through May 31, 1996, at $18.03 per barrel;
(iii) 9,500 barrels per day from June 1, 1996, through June 30, 1996, at $18.01
per barrel; (iv) 3,500 barrels per day from July 1, 1996, through December 31,
1996, at $17.48 per barrel; and (v) 1,500 barrels per day from January 1, 1997,
through June 30, 1997, at $17.23 per barrel.  The Company has entered into
additional swap agreements which provide for a NYMEX WTI indexed ceiling price
of $17.63 per barrel and a floor price of $16.50 per barrel for 3,000 barrels
per day from July 1, 1996 through December 31, 1996.  The above prices do not
reflect quality and location differentials attributable to the unique
characteristics of each core area's oil production.  The Company's current crude
oil hedges do not expose the Company to various basis risk differentials that
exist in the crude oil market.  See Item 7, "Management's Discussion and
Analysis of Financial Condition and Results of Operations".

     Substantially all of the Company's LA Basin crude oil production and all of
the Company's Sunniland Trend crude oil production is transported by two
pipelines owned by third parties. The inability of either one of these pipelines
to provide transportation services to the Company in the future could result in
involuntary curtailment of a significant portion of the Company's crude oil
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.

     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.  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". 

     Phibro Division of Salomon Inc. ("Phibro") and Phibro Energy USA, Inc.,
accounted for 16% and 12%, respectively, of the Company's total revenue
(exclusive of interest and other income) during 1995. Customers accounting for
more than 10% of total revenue for 1994 and 1993 were as follows: 1994 -- 
Phibro -- 19% and

                                       10
<PAGE>
 
Chevron -- 16%; 1993 -- Chevron -- 23%, Marathon -- 22% and Phibro --15%.  No
other single purchaser of the Company's products accounted for as much as 10% of
total sales during 1995, 1994 or 1993.  During 1995, 1994 and 1993, Chevron
accounted for 39%, 71% and 76% of the Company's oil and natural gas sales,
respectively. Additionally during 1995, Unocal and Scurlock Permian accounted
for approximately 28% and 19%, respectively, of the Company's oil and gas sales.
During 1995, Unocal was the purchaser of the Company's LA Basin oil production,
while Scurlock Permian was purchaser of oil production attributable to the
Sunniland Trend Properties.  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.

   Downstream 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 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 matters
affecting the Company's operations.

   Transportation and Sale of Natural Gas

     Prior to January 1, 1993, various aspects of the Company's natural gas
operations were subject to regulations 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

                                       11
<PAGE>
 
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 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 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 gas merchants,
including producers, did not compete on a "level playing field" in selling 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 gas supplies and delivery services from the most economical source,
whether interstate pipelines or other parties.  The FERC has issued final orders
in almost all restructuring proceedings, and has now commenced a series of
reviews of individual pipeline restructuring orders to determine whether
refinements are required regarding individual pipeline implementations of Order
No. 636.  In addition the FERC has announced its intention to reexamine certain
of its transportation related policies, including the appropriate manner in
which interstate pipelines release transportation capacity under Order No. 636,
and has issued a new policy regarding the use of non-traditional methods of
setting rates for interstate gas pipelines in certain circumstances as
alternatives to cost of service based rates.

     Although the FERC's actions, such as Order No. 636, do not regulate
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.

     Numerous petitions seeking judicial review of Order No. 636 and the
individual pipeline restructuring orders are pending.   It is not possible to
predict what, if any, effect the final restructuring rule will have on the
Company.  The Company does not believe, however, that it will be affected any
differently than other gas producers and marketers with which it competes.

     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.

  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.  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 Nos. 561 and 561-A) in which it revised its regulations governing
the rates that may be charged by oil pipelines.  The new rules, 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.  On October 28,
1994, the FERC issued two separate Orders (Nos. 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

                                       12
<PAGE>
 
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.  Challenges to these various rules are the subject of pending court
appeals.  The effect that these new rules may have on moving the Company's
liquid products to market cannot yet be determined.

  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.  Most 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 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 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.  Persons holding mineral
rights in wildlife refuge lands may obtain a Special Use Permit granted by the
Regional Director of the Fish and Wildlife Service for exploration, development
and production operations in compliance with regulations intended to protect
fish and wildlife in the refuge.  The Regional Director is given broad
discretion and authority in granting Special Use Permits and may specify
additional requirements to ensure that the proposed activities are compatible
with the Wildlife Refuge Act.

                                       13
<PAGE>
 
     Although the Company obtained environmental studies on its properties
in the LA Basin, 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.  In December 1995, the Company negotiated an agreement with
Chevron, a prior owner of the LA Basin Properties, to remediate sections of the
properties impacted by prior drilling and production operations.  Under this
agreement, Chevron agreed to investigate and potentially remediate specific
areas contaminated with volatile organic substances and heavy metals, and the
Company agreed to excavate and remediate crude oil contaminated soils.  The
Company is obligated to construct and operate (for the next 15 years) two five-
acre 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.

     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.  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 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 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 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.

                                       14
<PAGE>
 
     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 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
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 wastes have been disposed.

     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 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.

FEDERAL TAXATION

     At December 31, 1995, 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 $164 million.  Of

                                       15
<PAGE>
 
that amount, approximately $23 million is subject to separate return limitation
year restrictions and may only be utilized to the extent certain subsidiaries
which generated the NOLs have taxable income.  At December 31, 1995, the Company
had approximately $149 million of alternative minimum tax ("AMT") net operating
loss carryforwards available as a deduction against future AMT income.  In
addition, the Company had approximately $.8 million of investment tax credit
carryforwards and $7 million of percentage depletion carryforwards at December
31, 1995.  The NOL carryforwards expire from 1996 through 2010.  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 NOLs.

     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 Temporary 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.  Under Final Treasury
Regulations issued by the Internal Revenue Service, the Company does not believe
that an Ownership Change has occurred as of December 31, 1995.

     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
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 natural gas 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.

     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 Company's current and planned
drilling operations in the Sunniland Trend and Four Isle Dome involve increased
drilling risks of high pressures and mechanical difficulties, including stuck
pipe, collapsed casing and

                                       16
<PAGE>
 
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 situations, 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.

     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, 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 the Company's marketing subsidiary, Plains Marketing
& Transportation Inc.  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.

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 February 22, 1996, the Company had 202 full-time employees, none
of whom is represented by any labor union.  Approximately 98 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 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 the LA Basin of
California, the Sunniland Trend of South Florida, the Illinois Basin and the
Gulf Coast area of Louisiana. Its downstream marketing activities are
concentrated in Oklahoma, where it owns a two million barrel, above ground crude
oil terminalling and storage facility, Texas and the Gulf Coast area of
Louisiana. The Company's upstream operations contributed approximately 90% of
the Company's 1995 EBITDA proforma for the Illinois Basin Acquisition while the
Company's downstream activities accounted for the remainder. See Item 1,
"Business" for a discussion of the Company's exploration, acquisition,
development and exploitation activities and downstream businesses.

                                       17
<PAGE>
 
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. with respect to the
LA Basin 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 Commission which requires the
application of year-end prices for each year, held constant throughout the
projected reserve life.

     The following table sets forth the estimated quantities of proved and
proved developed reserves of crude oil (including condensate and natural gas
liquids) and natural gas owned by the Company as of December 31, 1993, 1994 and
1995 and the principal components of the changes in the quantities of reserves
for each of the years then ended.
<TABLE>
<CAPTION>
 
                                             AS OF OR FOR THE YEAR ENDED DECEMBER 31,
                                    ---------------------------------------------------------
                                           1993                1994               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                    33,390    39,861     38,810    49,397    61,459   51,009
Revisions of previous estimates      (6,478)   (7,753)    16,834     4,365     5,423    2,792
Extensions, discoveries, improved                                                      
 recovery and other additions         3,712     6,250      4,362     1,182    15,489    1,730
Sale of reserves                        (92)     (622)       (16)     (446)   (1,227)  (9,773)
Purchase of reserves in place        11,834    15,837      5,304        80    17,640      130
Production                           (3,556)   (4,176)    (3,835)   (3,569)   (4,376)  (2,778)
                                    -------   -------     ------   -------   -------   ------
                                                                                       
Ending balance                       38,810    49,397     61,459    51,009    94,408   43,110
                                    =======   =======     ======   =======   =======   ======
                                                                                       
PROVED DEVELOPED RESERVES                                                              
Beginning balance                    24,296    20,555     30,646    28,436    48,978   30,869
                                    =======   =======     ======   =======   =======   ======
Ending balance                       30,646    28,436     48,978    30,869    67,266   29,397
                                    =======   =======     ======   =======   =======   ======
</TABLE> 
 
     The following table sets forth the Present Value of Proved Reserves as of
December 31, 1993, 1994 and 1995.

<TABLE> 
                                     1993       1994        1995
                                    --------   --------   --------
                                           (IN THOUSANDS)
  <S>                                 <C>        <C>        <C> 
  Proved developed                  $106,212   $191,578   $272,634
  Proved undeveloped                  28,327     37,793     94,146
                                    --------   --------   --------
   Total proved                     $134,539   $229,371   $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.  In this regard, the information set
forth in the preceding tables includes revisions of reserve estimates
attributable

                                       18
<PAGE>
 
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.

     In accordance with the Commission's guidelines, the 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, 1995, is based on NYMEX spot price for WTI crude oil of
$19.55 per Bbl ($18.00 per Bbl WTI posted price) with variations therefrom based
on location and grade of crude oil.  The Company has entered into crude oil
financial swap arrangements to fix the NYMEX WTI index price for a significant
portion of its crude oil production.  These prices are included in the reserve
reports through the term of the arrangements.  On December 31, 1995, these
arrangements provided for a NYMEX WTI indexed average price for: (i) 11,000
barrels per day through March 31, 1996, at $18.07 per barrel; (ii) 10,000
barrels per day from April 1, 1996, through May 31, 1996, at $18.03 per barrel;
(iii) 9,500 barrels per day from June 1, 1996, through June 30, 1996, at $18.01
per barrel; (iv) 3,500 barrels per day from July 1, 1996, through December 31,
1996, at $17.48 per barrel; and (v) 1,500 barrels per day from January 1, 1997,
through June 30, 1997, at $17.23 per barrel.  The Company has entered into
additional swap arrangements which provide for a NYMEX WTI indexed ceiling price
of $17.63 per barrel and a floor price of $16.50 per barrel for 3,000 barrels
per day from July 1, 1996, through December 31, 1996.  Location and quality
differentials attributable to the Company's properties are not included in the
foregoing prices.  The crude oil swap agreements provide for monthly settlement
based on the differential between the contract price and the actual NYMEX WTI
crude oil price. The Company's current crude oil hedges do not expose the
Company to various basis risk differentials that exist in the crude oil market.
The overall average prices as of December 31, 1995, were $15.55 per Bbl of crude
oil, condensate and natural gas liquids and $1.05 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, 1994, 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 Commission.  See Note 15 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, 1995, the Company had working interests in 1,529 gross
(1,529 net) active oil wells and 48 gross (22 net) active natural gas wells.
These totals do not include the Company's royalty and overriding royalty
interests in approximately 135 gross (4 net) producing oil and natural gas
wells.

                                       19
<PAGE>
 
     The following table sets forth certain information with respect to the
developed and undeveloped acreage of the Company as of December 31, 1995.

<TABLE>
<CAPTION>
                                           DECEMBER 31, 1995
                              ----------------------------------------------
                              DEVELOPED ACRES(1)  UNDEVELOPED ACRES(2)(3)
                              ------------------  --------------------------
                               GROSS      NET       GROSS        NET(4)
                              -------    ------   -----------  -------------
<S>                            <C>       <C>         <C>         <C>
California..................    3,707     3,634           10          10
Florida(5)..................   12,502    12,502       86,935      77,385
Illinois....................   15,887    13,885       33,653      15,416
Indiana.....................    1,155       854        2,562       1,216
Kansas......................       --        --       50,193      39,421
Kentucky....................       --        --        1,321         521
Louisiana(6)................       --        --       19,511      10,653
Oklahoma....................      640        88           --          --
Texas.......................       --        --          659         186
Utah........................   14,551     7,276           --          --
                               ------    ------      -------     -------
  Total.....................   48,442    38,239      194,844     144,808
                               ======    ======      =======     =======
</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) Does not include: (i) approximately 84,000 gross (39,500 net) acres located
    within Exploration Permit WA-246-P in the Northwest Territory of Australia;
    (ii) approximately 320,000 gross (264,000 net) acres located within Block
    AC/P14 in the Vulcan Sub-basin (Timor Sea) on the Northwest shelf of
    Australia in which the Company holds exploration rights; (iii) approximately
    143,000 gross (10,725 net) acres located within an exploration license
    located in New Caledonia; or (iv) approximately 8 million gross (7.7 million
    net) acres in Pakistan to which the Company holds exploration rights.  See
    Item 1, "Business--Exploration--Current Exploration Projects--1995 Domestic
    and International Exploration Activities".
(4) Less than 5% of total net undeveloped acres are covered by leases that
    expire in 1996 and 1997.
(5) Does not include approximately 8,500 gross (4,250 net) acres under seismic
    option.
(6) Does not include approximately 20,000 gross (6,700 net) acres under seismic
    option.

                                       20
<PAGE>
 
DRILLING ACTIVITIES

     Certain information with regard to the Company's drilling activities during
the years ended December 31, 1993, 1994 and 1995 is set forth below:

<TABLE>
<CAPTION>
                                  YEAR ENDED DECEMBER 31,
                           --------------------------------------
                               1993         1994         1995
                           ------------  -----------  -----------
                           GROSS   NET   GROSS  NET   GROSS  NET
                           -----  -----  -----  ----  -----  ----
<S>                        <C>    <C>     <C>   <C>    <C>   <C>
Exploratory Wells: 
  Oil....................   0.00   0.00   0.00  0.00   0.00  0.00
  Natural gas............   0.00   0.00   0.00  0.00   0.00  0.00
  Dry....................   5.00   1.90   6.00  4.39   1.00  0.40
                           -----  -----   ----  ----   ----  ----
      Total..............   5.00   1.90   6.00  4.39   1.00  0.40
                           =====  =====   ====  ====   ====  ====
Development Wells: 
  Oil....................  13.00  13.00   1.00  1.00   0.00  0.00
  Natural gas............   0.00   0.00   0.00  0.00   0.00  0.00
  Dry....................   2.00   1.80   0.00  0.00   1.00  0.50
                           -----  -----   ----  ----   ----  ----
      Total..............  15.00  14.80   1.00  1.00   1.00  0.50
                           =====  =====   ====  ====   ====  ====
Total Wells:       
  Producing..............  13.00  13.00   1.00  1.00   0.00  0.00
  Dry....................   7.00   3.70   6.00  4.39   2.00  0.90
                           -----  -----   ----  ----   ----  ----
      Total..............  20.00  16.70   7.00  5.39   2.00  0.90
                           =====  =====   ====  ====   ====  ====
</TABLE>

     At December 31, 1995, the Company was in the process of drilling 1
gross (1 net) developmental well.  See Item 1, "Business--Acquisition and
Exploitation" and "--Productive Wells and Acreage" for additional information
regarding exploitation activities, including waterflood patterns, workovers and
recompletions.

PRODUCTION AND SALES

     The following table presents certain information with respect to oil
and natural gas production attributable to the Company's properties, the revenue
derived from the sale of such production, average sales price received and
average production costs during the three years ended December 31, 1993, 1994
and 1995.

<TABLE>
<CAPTION>
 
                                                   YEAR ENDED DECEMBER 31,
                                                 ---------------------------
                                                  1993     1994        1995
                                                 ------   -------    -------
                                           (IN THOUSANDS, EXCEPT UNIT PRICES)
<S>                                              <C>       <C>        <C>
    Production:                                                   
     Crude oil and natural gas liquids (Bbls)..    3,556     3,835      4,376
     Natural gas (Mcf).........................    4,176     3,569      2,788
     BOE.......................................    4,252     4,430      4,839
                                                                  
    Revenue:                                                      
     Crude oil and natural gas liquids.........  $50,986   $52,331    $61,241
     Natural gas...............................    6,521     4,903      2,839
                                                 -------   -------    -------
      Total....................................  $57,507   $57,234    $64,080
                                                 =======   =======    =======  
 
    Average sales price:
     Crude oil and natural gas liquids (Bbl)...  $ 14.34   $ 13.65    $ 13.99
     Natural gas (Mcf).........................  $  1.56   $  1.37    $  1.02
     Per BOE...................................  $ 13.52   $ 12.92    $ 13.24
 
    Production costs per BOE...................  $  6.65   $  6.15    $  6.25
</TABLE>

                                       21
<PAGE>
 
CRUDE OIL STORAGE AND TERMINALLING FACILITY

     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.  See Item
1, "Business -- Downstream Activities".

OTHER FACILITIES

     The Company currently leases offices containing approximately 46,000 square
feet in Houston, Texas.

ITEM 3.   LEGAL PROCEEDINGS

     On April 27, 1992, the Company and certain of its officers and directors
and a former director and officer were named as defendants in a lawsuit filed in
the United States District Court for the Southern District of Texas captioned
Judith Rubinstein and Howard Greenwald v. Collins, et al., C.A. No. H-92-1297.
The complaint brings a class action (the class period of which is October 23,
1991, through April 13, 1992) for, among other things, alleged violations of
Sections 10(b) and 20(a) of the Exchange Act and for state law fraud and
negligent misrepresentation, arising out of certain alleged misrepresentations
and omissions in the Company's disclosures regarding its onshore natural gas
exploration activities.  The plaintiffs, who purport to have purchased their
Common Stock in open market transactions (300 and 375 shares, respectively),
contend the class is entitled to approximately $30 million for compensatory
damages and punitive damages in an unspecified amount.  The Company filed a
motion to dismiss in July 1992.  On August 24, 1992, the Court entered an Order
of Dismissal and a Final Judgment dismissing the plaintiffs' complaint for
failure to state a claim under the federal securities laws and/or under the
common law of the State of Texas.  On September 10, 1992, the plaintiffs filed a
Notice of Appeal of the District Court's judgment with the United States Court
of Appeals for the Fifth Circuit (No. 92-2736).  On May 5, 1994, the Fifth
Circuit Court ruled, among other things, that the plaintiffs had sufficiently
pleaded claims under the federal securities laws and under Texas common law and
reversed the trial court's dismissal and remanded the case to the trial court
for further proceedings.

     On July 27, 1993, a second case similar to the Rubinstein case described in
the preceding paragraph was filed in the United States District Court for the
Southern District of Texas captioned Gloria Moroson v. Collins, et al., C.A. No.
H-93-2305, naming the Company and certain of its officers and directors and a
former director and officer as defendants.  The complaint brings a class action
(the class period of which is May 11, 1992, through August 14, 1992) for, among
other things, alleged violations of Sections 10(b) and 20(a) of the Exchange Act
and for state law fraud and negligent misrepresentation, arising out of certain
alleged misrepresentations and omissions in the Company's disclosures regarding
its onshore natural gas exploration activities.  The plaintiff, who purports to
have purchased 50 shares of Common Stock in an open market transaction, contends
the class is entitled to approximately $60 million for compensatory damages and
punitive damages in an unspecified amount.  These amounts are alleged to be in
addition to the damages claimed in the Rubinstein case.  In June 1994, the trial
court granted the Company's motion to consolidate the Rubinstein and Moroson
cases.

     On February 20, 1996, the Court denied the Company's motion for summary
judgment in these two cases and set a trial date for May 8, 1996. The Company
expects the cases to go to trial before a jury on or about such date. Although
the Company believes these complaints to be without merit and intends to
vigorously defend these lawsuits, if the plaintiffs were awarded, and the
Company were ultimately required to pay, a substantial portion of the $90
million in compensatory damages sought by the plaintiffs, it would have a
material adverse effect on the Company.

     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

                                       22
<PAGE>
 
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 lands 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.  No trial date has been set
in this case.  Exxon and Calumet have filed a motion to dismiss the
counterclaims.  The Court has not yet ruled on such motion.  Calumet believes
the counterclaim challenging the validity of certain oil and natural gas leases
owned by Calumet to be without merit and intends to vigorously defend against
such claim.

     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 37, 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 44, 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 38, 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, Vice President, Chief Financial Officer 
and Treasurer                                                 Officer Since 1987

     Mr. Kramer, age 40, has been Vice President and Chief Financial Officer of
the Company since 1992.  He was Vice President and Treasurer from 1988 to 1992,
Treasurer from 1987 to 1988, and Controller from 1983 to 1987.

                                       23
<PAGE>
 
G. M. McCarroll, Vice President-Exploration and Land          Officer Since 1989

     Mr. McCarroll, age 38, became Vice President-Exploration and Land in
February 1996.  He had been Vice President-Land of the Company since 1989,
except for the period of May through July 1991 when he was Vice President of a
land development company in Lafayette, Louisiana.  From 1988 to 1989 he was a
consultant to the Company for acquisitions and land functions.

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

     Mr. Patterson, age 48, 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 38, 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 47, has been Vice President-Administration and Human
Resources since 1991.  She was Manager of Office Administration of the Company
from 1984 to 1991.

                                       24
<PAGE>
 
                                    PART II

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

     The Company's $.10 par value common stock ("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  February 26, 1996, was 1,622.

     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.
 
                                                   HIGH     LOW
                                                  ------  -------
     1995:                      
     1st Quarter................................ $ 7 5/8   $5 1/2
     2nd Quarter................................   9 3/4    7 5/8
     3rd Quarter................................  10 3/4    7 5/8
     4th Quarter................................   9        6 13/16
                                
     1994:                      
     1st Quarter................................ $ 7       $5 3/8
     2nd Quarter................................   6 1/2    5 5/8
     3rd Quarter................................   7 7/8    5 3/4
     4th Quarter................................   6 3/4    5 3/8

     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 $100 million
12% Senior Subordinated Notes Due 1999 (the "12% Notes") and the Revolving
Credit Facility from paying dividends on the Common Stock.

                                       25
<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,                        
                             ------------------------------------------------------------    
                             1991          1992       1993          1994         1995        
                             ----          ----       ----          ----         ----        
                                   (IN THOUSANDS, EXCEPT PER SHARE INFORMATION)       
<S>                          <C>           <C>        <C>           <C>          <C>   
STATEMENT OF OPERATIONS
 DATA:
Revenues:
 Oil and natural gas sales   $ 14,872      $ 38,400   $ 57,507      $  57,234    $ 64,080
 Marketing, transportation    
  and storage                  64,434        93,838    128,186        199,239     339,826
 Other                            189           413        335            223         319
                             --------      --------   --------      ---------    --------
  Total revenue                79,495       132,651    186,028        256,696     404,225
                             --------      --------   --------      ---------    -------- 
Costs and expenses:           
 Production expenses            3,466        19,329     28,285         27,220      30,256
 Purchases, transportation                  
  and storage                  63,200        92,107    124,390        193,049     333,460
 General and administrative     3,825         8,592      7,724          6,966       7,215
 Depreciation, depletion
  and amortization.........    18,581(1)     12,155     36,980 (2)     16,305      17,036
 Interest expense               3,251         3,776      8,847         12,585      13,606
 Provision for income taxes        45            --         --             --          --
                             --------      --------   --------      ---------    --------
  Total expenses               92,368       135,959    206,226        256,125     401,573
                             --------      --------   --------      ---------    --------
Net income (loss)            $(12,873)(1)  $ (3,308)  $(20,198)(2)  $     571    $  2,652
                             ========      ========   ========      =========    ========  
Net income (loss) per
 common and common
 equivalent share..........  $  (1.59)     $   (.32)  $  (1.77)     $     .04    $    .16
Weighted average number of
 common and
 common equivalent shares       8,142        10,536     11,438         11,625      15,981
 
OTHER FINANCIAL DATA:
 Net cash provided by
  operating activities.....  $  6,145      $ 11,435   $ 10,397      $  18,369    $ 16,984
 Cash flow from operations
  (earnings before
  depreciation,
  depletion and
  amortization)              $  5,708      $  8,847   $ 16,782      $  16,876    $ 19,688
 EBITDA(3)                   $  9,004      $ 12,623   $ 25,629      $  29,461    $ 33,294
 

                                                  AS OF DECEMBER 31                             
                             ------------------------------------------------------------   
                             1991          1992       1993          1994         1995       
                             ----          ----       ----          ----         ----       
BALANCE SHEET DATA:
 Cash and cash equivalents   $  3,388      $ 25,149   $  4,862 (4)  $   2,791(4) $  6,129
 Working capital (deficit)     (3,441)       13,065    (13,986)        (4,465)     (4,749)
 Property and equipment,                                              
  net                          78,176       144,692    191,985        217,602     280,538
 Total assets                  96,754       199,093    236,667        266,904     352,046
 Long-term debt                42,173       100,000    141,600        149,600     205,089
 Other long-term                                                      
  liabilities                     324         2,506        967          3,754       1,547
 Redeemable preferred stock        --            --         --         20,937          --
 Total stockholders'                                                  
  equity, including                                                   
  non-redeemable                                                      
  preferred stock              34,135        63,333     44,997         46,462      77,029
</TABLE>
---------------
(1) Includes a noncash charge of approximately $11 million related to a
    writedown of the capitalized costs of the Company's proved oil and natural
    gas properties as a result of unusually low seasonal gas prices at June 30,
    1991.
(2) A large portion of the Company's reserve base is comprised of long-life oil
    properties that are sensitive to low crude oil prices.  During the fourth
    quarter of 1993, crude oil prices declined significantly, with the posted
    price for WTI crude oil ending the year at $12.50 per Bbl, the lowest year-
    end oil price in the 13 years since U.S. crude oil prices were deregulated.
    Such low prices had an adverse affect on the quantities and Present Value of
    Proved Reserves at December 31, 1993, and led to a noncash charge of $20
    million related to a writedown of the capitalized costs of the Company's
    proved oil and natural gas properties.

                                       26
<PAGE>
 
(3) EBITDA means earnings before interest, taxes, depreciation, depletion and
    amortization. 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.
(4) Includes restricted cash of $1.1 million and $1.5 million as of December 31,
    1993 and 1994, respectively, attributable to compensating balance
    requirements.

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

GENERAL

     For the three years ended December 31, 1995, the Company reported
significant increases in proved reserves, production and cash flow from oil and
natural gas producing activities.  Such increases are primarily the result of
the acquisition and subsequent exploitation of its LA Basin and Sunniland Trend
Properties and the recent acquisition of the Illinois Basin Properties.  These
three core areas are comprised primarily of crude oil properties and together
account for approximately 96% of the Company's year-end 1995 proved reserves.
See Item 1, "Business--Acquisition and Exploitation--Current Exploitation
Projects".  See Note 9 to the accompanying Consolidated Financial Statements for
pro forma information giving effect to the acquisition of the Illinois Basin
Properties as if such transaction occurred on January 1, 1995.

RESULTS OF OPERATIONS

  Three years ended December 31, 1995

     During 1995 and 1994, the Company reported increases in total production,
upstream gross margin and downstream gross margin while decreasing per unit
general and administrative ("G&A") expenses.  The Company reported net income of
$2.7 million on total revenue of $404.2 million for the year ended December 31,
1995.  This compares with net income of $571,000 in 1994 and a net loss of $20.2
million in 1993.  Total revenue for 1994 and 1993 was $256.7 million and $186.0
million, respectively.  The 1993 loss included a $20 million noncash charge
related to the writedown of the net capitalized costs of the Company's proved
oil and gas properties due to unusually low oil prices.  The Company follows the
full cost method of accounting which limits the net capitalized costs of proved
oil and gas properties to the present value (discounted at 10%) of estimated
future net cash flows after income taxes (the "Standardized Measure").  Due to
the low oil price at December 31, 1993, such costs exceeded the Standardized
Measure by approximately $20 million.  At year-end 1995 and 1994, the
Standardized Measure of the Company's proved reserves exceeded the book carrying
cost by approximately $107.0 million and $54.0 million, respectively.  However,
the Commission's full cost accounting rules do not allow the Company to
reinstate the $20.0 million book value written off in 1993.

     EBITDA increased 13% in 1995 to $33.3 million from the $29.5 million
reported in 1994 and nearly 30% more than the $25.6 million reported in 1993.
Cash flow from operations (earnings before depreciation, depletion and
amortization) increased to $19.7 million in 1995, 17% above the $16.9 million
and $16.8 million reported for 1994 and 1993, respectively.  Net cash provided
by operating activities was $17.0 million for the year ended December 31, 1995
as compared to $18.4 million for 1994 and $10.4 million in 1993.  A large
portion of the increase in 1994 over 1993 was attributable to proceeds received
during 1994 from the sale of crude oil inventory that was purchased during 1993.

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

<TABLE>
<CAPTION>
                                     YEAR ENDED DECEMBER 31,
                                     ------------------------
                                     1995     1994       1993
                                     ----     ----       ---- 
                                      (IN THOUSANDS, EXCEPT 
                                    PER UNIT DATA) (UNAUDITED)
<S>                                 <C>      <C>        <C>   
AVERAGE DAILY PRODUCTION VOLUMES
 Barrels of oil:
  LA Basin........................     7.6      7.3        7.2
  Sunniland Trend.................     3.4      2.7        1.3
  Illinois Basin..................     0.6       --         --
  Other...........................     0.4      0.5        1.2
                                      ----     ----       ----
   Total..........................    12.0     10.5        9.7
                                      ====     ====       ====
 Mcf of natural gas:                                
  LA Basin........................     4.5      4.5        5.0
  Other...........................     3.1      5.3        6.4
                                      ----     ----       ----
   Total..........................     7.6      9.8       11.4
                                      ====     ====       ====
 Barrels of oil equivalent:                         
  LA Basin........................     8.4      8.1        8.0
  Sunniland Trend.................     3.4      2.7        1.3
  Illinois Basin..................     0.6       --         --
  Other...........................     0.9      1.3        2.3
                                      ----     ----       ----
   Total..........................    13.3     12.1       11.6
                                      ====     ====       ====
 
AVERAGE SALES PRICE               
 Per barrel of oil................  $13.99   $13.65     $14.34
                                    ======   ======     ======  
 Per Mcf of natural gas...........   $1.02    $1.37      $1.56
                                     =====    =====      =====  
 
UNIT ECONOMICS                     
 Average sales price per BOE......  $13.24   $12.92     $13.52
 Production expenses per BOE......    6.25     6.15       6.65
                                    ------   ------     ------
 Gross margin per BOE.............    6.99     6.77       6.87
 Upstream G&A expenses per BOE....     .99     1.04       1.34
                                    ------   ------     ------
 Gross profit per BOE.............  $ 6.00   $ 5.73     $ 5.53
                                    ======   ======     ======  
</TABLE>

     Oil and natural gas production volumes totaled 4.8 million BOE in 1995, a
9% increase over 1994's level of 4.4 million BOE and a 21% increase over the
1993 base level of 4.0 million BOE. The base level production for 1993 excludes
approximately 263,000 BOE associated with a marginal property disposed of in
late 1993 and not previously included in the Company's proved reserves. Oil
production increased by 14% to 4.4 million Bbls from 1994's level of 3.8 million
Bbls and 33% over the 1993 base level of 3.3 million Bbls. In 1992, the Company
increased its focus on mature but underdeveloped crude oil producing properties.
As a result of this increased focus on crude oil properties and normal
production declines in the Company's Gulf Coast properties, natural gas
production declined by 22% to 2.8 Bcf in 1995 as compared to 3.6 Bcf in 1994.
Natural gas production was 4.2 Bcf in 1993.

     Primarily as a result of increased production volumes from the Company's
acquisition and exploitation activities, oil and natural gas revenues increased
to $64.1 million in 1995 as compared to $57.2 million in 1994 and $57.5 million
in 1993.  The Company routinely seeks to manage its exposure to commodity prices
through the prudent use of hedges, primarily through long-term fixed price
arrangements or financial swaps.  During the three years ended December 31,
1995, the majority of the Company's crude oil production was sold under such
arrangements.  The average oil price received for the year ended December 31,
1995, which is an average of prices received under fixed and floating price
sales arrangements, was $13.99 per Bbl, approximately 3% more than the $13.65
per Bbl received in 1994 and 2% less than the $14.34 received in 1993.  The
Company's average natural

                                       29
<PAGE>
 
gas price received was $1.02 per Mcf during 1995, down 26% from the $1.37 per
Mcf received in 1994 and 35% below the $1.56 per Mcf received in 1993.  The
Company's oil and natural gas production yields lower product prices than
benchmark NYMEX prices due to location and quality differentials.  Financial
swap arrangements and futures transactions entered into by the Company to hedge
production are included in the foregoing prices.  Such transactions had the
effect of decreasing the overall average price per BOE by $.19 in 1995 and
increasing the average price by $.16 and $.18 for 1994 and 1993, respectively.
During 1995, the Company's unit gross margin (gross margin per BOE) and unit
gross profit averaged $6.99 per BOE ($1.17 per MCFE) and $6.00 per BOE ($1.00
per MCFE), respectively.

     Marketing, transportation, storage and terminalling activities generated
gross margin (total revenues less purchases, transportation and storage and
terminalling costs) of $6.4 million on total revenues of $339.8 million as
compared to 1994's gross margin of $6.2 million on total revenues of $199.2
million.  Gross margin totaled $3.8 million on total revenues of $128.2 million
for 1993.  The trend of increased revenues and associated gross margin is
reflective of increases in the quantity of crude oil marketed on behalf of other
producers and premium resale markets made available by the Cushing Terminal.
Gross margin for 1994 included approximately $1.5 million of income resulting
from the occurrence of a contango crude oil futures market generated principally
during the first half of the year when third party storage and terminalling
operations, the Company's fundamental downstream business activity, were
commencing.  A contango crude oil futures market exists when the futures price
of a subsequent month exceeds the price of a prior month.  Such market allows
the Company to simultaneously purchase and sell crude oil and lock-in a profit.
The Cushing Terminal provides the mechanism to capitalize on a contango market
due to the ability to receive, store and redeliver crude oil.  The Company
expects its downstream activities to continue to increase.

     During 1995, the Company continued its trend of reducing unit production
and unit G&A expenses on properties held throughout the year. Excluding the
fourth quarter impact of the Illinois Basin Acquisition, unit production
expenses decreased 3% to $5.97 per BOE as compared to $6.15 per BOE in 1994 and
were 10% below 1993's unit production expenses of $6.65 per BOE. These decreases
are attributable to improved operating and cost control practices implemented by
the Company and increased production volumes as well as to the disposition of
certain properties. Including the impact of the Illinois Basin Properties, unit
production expenses were $6.25 per BOE during 1995. For the two months of
operations included in 1995's results, unit production expenses for the Illinois
Basin Properties averaged $12.00 per BOE. The Illinois Basin Properties were
operated by Marathon during such period. An integral component of the Company's
plan of exploitation for this property is a significant reduction in unit
production expenses. The Company assumed operations from Marathon on January
1, 1996. Total production expenses increased 11% to $30.3 million in 1995 as
compared to $27.2 million in 1994. Total production expenses were $28.3 million
in 1993.

     In the Company's upstream segment, unit G&A expenses decreased for the
third consecutive year totaling $.99 per BOE for 1995, down 5% as compared to
$1.04 per BOE in 1994 and 26% below the level in 1993 of $1.34 per BOE. These
reductions are directly attributable to the Company's ongoing cost reduction and
cost control efforts and increased production levels. Downstream G&A expenses
for 1995 and 1994 were relatively constant at $2.4 million for each period while
downstream G&A expenses for 1993 totaled approximately $2.0 million. The
increase in G&A expenses over the 1993 level was attributable to the continued
expansion of the Company's marketing and terminalling activities. Combined G&A
expenses for both the upstream and downstream activities totaled $7.2 million,
$7.0 million and $7.7 million in 1995, 1994 and 1993, respectively.

     DD&A per BOE was approximately $3.02 in 1995 as compared to $3.17 in 1994
and $3.57 in 1993 (excluding the $20 million noncash writedown in 1993 in the
carrying costs of the Company's oil and natural gas properties). Primarily as a
result of increased production levels, total DD&A for the year ended December
31, 1995 was $17.0 million, up 4% as compared to $16.3 million in 1994 and
relatively constant with 1993's level of $17.0 million (excluding the noncash
writedown).

                                       30
<PAGE>
 
     Interest expense, net of capitalized interest, for 1995 increased to $13.6
million as compared to $12.6 million in 1994 and $8.8 million in 1993, primarily
due to higher borrowing levels related to the Company's acquisition,
exploitation, development and exploration activities.  In addition, interest
capitalization decreased in 1994 following the completion of the Cushing
Terminal, resulting in a corresponding increase in interest expense for 1994.
During 1993, 1994 and 1995, the Company capitalized $4.3 million, $2.7 million
and $3.1 million of interest, respectively.

     The Company has a deferred tax asset of approximately $18.3 million at
December 31, 1995.  The realization of the tax asset is dependent on the
Company's ability to generate taxable earnings in future periods.  A valuation
allowance for such amount has been recorded to reflect the estimated amount of
the deferred tax asset which may not be realized due to the expiration of a
portion of the Company's tax net operating loss ("NOL") and tax credit
carryforwards.  Future realization of the tax asset will be affected by recent
additions to the Company's oil and gas reserves and the resulting increases in
anticipated future income.  Management is currently reassessing the ability to
realize a portion of such asset based on these reserve additions.

     Although the Company recorded net income for 1995 and 1994, no provision
for income taxes was reflected but rather the valuation allowance discussed
above was adjusted.

CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION

     The Company has historically relied on working capital generated by cash
flow from operating activities, various types of debt financing and proceeds
from the sale of preferred and common stock to finance its capital expenditures.
The Company believes that it has the available capital resources to fund its
obligations and planned capital expenditures. The Company currently estimates
that its 1996 capital expenditures excluding acquisitions will aggregate
approximately $48 million, approximately $40 million of which will be spent on
exploitation and development activities, $5 million of which will be spent on
exploration activities and the remaining $3 million of which will be spent on
other capital projects, primarily to expand downstream activities. A substantial
portion of these planned capital expenditures are discretionary and actual
expenditures may vary based on crude oil and natural gas prices, results from
geological and geophysical studies and drilling operations. In addition, the
Company intends to continue to pursue the acquisition of underdeveloped
producing properties.

     The Company has a $75 million revolving credit facility (the "Revolving
Credit Facility") with a group of five banks (the "Lenders"). In December 1995,
the Revolving Credit Facility and borrowing base thereunder was increased to $75
million from $65 million. The Revolving Credit Facility is secured by the oil
and natural gas properties of the Company and is guaranteed by all of the
Company's subsidiaries other than PMCT, Inc. ("PMCT"), which guarantees are
secured by all of the oil and natural gas properties of the Company and its
subsidiaries (except Plains Illinois Inc. ("Plains Illinois"), the subsidiary
which holds the Illinois Basin Properties) and the stock of all guaranteeing
subsidiaries. The Cushing Terminal is not pledged as security for any of the
Company's debt. The Revolving Credit Facility 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 1/2% per annum on the unused portion of the borrowing base.
The Revolving Credit Facility converts to a term loan on October 1, 1997, with a
final maturity of April 1, 1998. Indebtedness of up to $65 million under the
Revolving Credit Facility bears interest at the option of the Company at (i)
LIBOR plus 2% or (ii) the higher of the Base Rate plus 5/8% and the federal
funds rate plus 1-1/8%. Indebtedness in excess of $65 million under the
Revolving Credit Facility bears interest at an additional 1/2% through December
31, 1996, and an additional 1% thereafter. At December 31, 1995, outstanding
borrowings under the Revolving Credit Facility were $56 million. An additional
$1 million was reserved against the issuance of a standby letter of credit.

                                       31
<PAGE>
 
     Plains Illinois established the Illinois Basin Acquisition Indebtedness to
fund the acquisition of the Illinois Basin Properties.  The Illinois Basin
Acquisition Indebtedness has a final maturity of December 22, 1999, with monthly
payments of interest and principal required from 85% of Field Level Net
Revenues.  Field Level Net Revenues are defined as revenues derived from the
sale of production from the Illinois Basin Properties less a predefined amount
of production expenses equal to the Company's original projections of such
expenses or actual production expenses, whichever are less, on a monthly basis.
The Illinois Basin Acquisition Indebtedness bears interest at LIBOR plus 2%
through September 30, 1996, and LIBOR plus 3%, thereafter.  The Company has
entered into a one year interest rate swap agreement with INCC, one of the
lending banks, to fix the LIBOR portion of the interest rate at 5.35%.

     The Illinois Basin Acquisition Indebtedness is secured by a first lien on
the Illinois Basin Properties and is guaranteed by the Company. The Illinois
Basin Acquisition Indebtedness contains covenants which, among other things
prohibit (i) Plains Illinois from making certain loans and investments and (ii)
the incurrence of additional indebtedness by Plains Illinois.

     The Company intends to sell privately $150 million in principal amount of
senior subordinated notes due 2006 (the "Notes"). The Company anticipates that
such sale (the "Offering"), if consummated, would be completed in March 1996.
The net proceeds to the Company from the sale of the Notes are estimated to be
$145.8 million after deducting expenses of the transaction. An aggregate $106
million of such net proceeds will be used to redeem all of the 12% Notes at 106%
of the $100 million principal amount outstanding. The remaining $39.8 million
together with an additional $2.2 million to be borrowed under the Company's
Revolving Credit Facility will be used to retire the Illinois Basin Acquisition
Indebtedness.

     As of February 26, 1996, the Company had $58 million outstanding under the
Revolving Credit Facility and approximately $42 million outstanding under the
Illinois Basin Acquisition Indebtedness. Subsequent to the Offering and in order
to fully retire the Illinois Basin Acquisition Indebtedness, the Company will
increase the amount outstanding under the Revolving Credit Facility by $2.2
million. After the Offering, and in accordance with a commitment letter from
INCC, the Company intends to increase the Revolving Credit Facility to $125
million, to secure the Revolving Credit Facility with all of the Company's oil
and natural gas properties and to cause all of the Company's principal
subsidiaries to guarantee the Revolving Credit Facility. As so modified, the
Revolving Credit Facility will bear interest at LIBOR plus 1.75% per annum, will
convert to a term loan two years after the date of modification and will be
repayable in equal quarterly installments for five years following the
conversion to a term loan. Final maturity of the Revolving Credit Facility will
be seven years after the date of modification.
 
     During 1995, the Company's marketing subsidiary established an $80 million
uncommitted secured demand transactional line of credit (the "Transactional
Facility") with three 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 the marketing subsidiary 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.  At December 31, 1995, approximately $49.1 million in
letters of credit were outstanding under the Transactional Facility.

     PMCT has established a $20 million sublimit (the "Sublimit") within the
Transactional Facility for standby letters of credit and borrowings to finance
crude oil purchased in connection with operations at the Company's crude oil
terminal and storage facility in Cushing, Oklahoma.  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.  Standby
letters of credit and borrowings under the Sublimit are secured by all of the
assets of PMCT and are recourse only to the subsidiary.  At December 31, 1995,
no letters of credit or borrowings were outstanding under the Sublimit.  Letters
of credit under the Transactional Facility are issued for up to seventy day
periods and bear fees of 1.5% per annum.  Borrowings incur interest at the
option of the borrower at (i) the Base Rate plus 5/8% or (ii) LIBOR plus 2%.
All financings under the Transactional Facility, which expires in August 1996,
are at the discretion of the lenders.  Aggregate cash borrowings by both
subsidiaries are limited to $20 million.

     On May 25, 1995, all outstanding shares of the Company's Series C
Cumulative Convertible Preferred Stock (the "Series C Preferred Stock"),
including accrued dividends, were converted into approximately 3.6 million

                                       32
<PAGE>
 
shares of Common Stock.  The Series C Preferred Stock was sold in a private
placement for net proceeds of approximately $20 million in 1994.  Proceeds of
the placement were used to retire an $11.5 million bridge loan, incurred to
acquire an approximate 50% working interest in the Sunniland Trend Properties in
1994, to fund exploitation of such properties and to reduce the amount
outstanding on the Revolving Credit Facility.

     At December 31, 1995, the Company had a working capital deficit of
approximately $4.7 million compared to a deficit of $4.5 million at December 31,
1994.  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.

  Changing Oil and Natural Gas Prices

     The Company is heavily dependent on 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, 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. For 1996, the Company has committed an average of
approximately 8,500 Bbls of oil per day to fixed price arrangements that expire
at various times throughout 1996. Such arrangements represent approximately 55%
of the Company's average daily oil production for 1995 pro forma for the
Illinois Basin Acquisition and partially mitigate the adverse impact of
potential oil price declines on the Company's operating results. The Company
enters into hedging arrangements which provide for settlement based on index
prices that correlate directly to that being received for its physical delivery
of its crude oil production. Accordingly, the Company's current crude oil hedges
do not expose the Company to various basis risk differentials that exist in the
crude oil market. 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".

  Investing Activities

     Net cash flows used in investing activities were $64.4 million, $40.2
million and $76.5 million for the years ended December 31, 1995, 1994 and 1993,
respectively. Included in such amounts are payments, net of cash received from
property sales and reimbursements from partners, for acquisition, exploration
and development costs of $63.9 million, $39.6 million and $52.8 million for the
same periods, respectively. Such payments for 1995 include $45.0 million related
to the cash portion of the acquisition of the Illinois Basin Properties and for
1994 include approximately $12.4 million related to the cash portion of the
acquisition of the Sunniland Trend Properties. The Company expended $1.1
million, $2.1 million and $23.6 million in 1995, 1994 and 1993, respectively,
for other property additions, primarily attributable to the Cushing Terminal
which was completed in December 1993. The total cost of the Cushing Terminal,
including 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 ten million barrels of
storage, was approximately $30.9 million.

  Financing Activities

     Net cash provided by financing activities amounted to $52.3 million, $19.3
million and $44.7 million for 1995, 1994, and 1993, respectively.  Aggregate
proceeds from long-term borrowings for these same years were $83.6 million,
$70.0 million and $72.2 million, respectively, while payments of long-term debt
were $30.7 million, $60.5 million and $36.6 million for the respective periods.
The Illinois Basin Acquisition Indebtedness of $42 million is included in
aggregate 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 1994 and 1993 include net payments and receipts from
short-term borrowings of $9.6 million related to the Transactional Facility.
Such amounts were borrowed to finance the purchase of crude oil inventory in
1993 which was sold in 1994.  Financing activities include proceeds from the
sale of capital stock of $869,000, $20.6 million and $803,000 in

                                       33
<PAGE>
 
1995, 1994 and 1993, respectively.  The 1994 proceeds were primarily from the
issuance of the Series C Preferred Stock.

  Commitments

     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 270.  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 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.

     Although the Company obtained environmental studies on its properties in
the LA Basin, 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. In connection with the purchase of the LA Basin Properties, Stocker
received a limited indemnity from Chevron for certain conditions if they violate
applicable local, state and federal environmental laws and regulation 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 $14 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 1995, 1994 and 1993 include $1.0 million, $1.1 million and
$1.8 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.

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-22 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.

                                       34
<PAGE>

                                 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 1996 Annual Meeting of Stockholders (the "Proxy
Statement") to be filed within 120 days after December 31, 1995, 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.

                                    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

              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) - Credit Agreement dated December 22, 1995, between Plains
                     Illinois Inc. and Internationale Nederlanden (U.S.) Capital
                     Corporation (incorporated by reference to Exhibit 2.2 to
                     Form 8-K dated January 4, 1996.)
 

                                       35
<PAGE>
 
           3(a)   - Second Restated Certificate of Incorporation of the Company.
           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).
           4(a)   - Specimen Common Stock Certificate (incorporated by
                    reference to Exhibit 4 to the Company's Form S-1
                    Registration Statement (Reg. No. 33-33986)).
           4(b)   - Form of Indenture dated as of October 1, 1992, between the
                    Company and Ameritrust Texas National Association, as the
                    Trustee (incorporated by reference to Exhibit 4 to
                    Amendment No. 3 to Form S-3 Registration statement (Reg.
                    No. 33-50572)).
           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).
           10(a)  - Second Amended and Restated Credit Agreement dated as of
                    February 11, 1994, between Internationale Nederlanden
                    (U.S.) Capital Corporation (incorporated by reference to
                    Exhibit (10a) to the Company's Annual Report on Form 10-K
                    for the year ended December 31, 1993) (the "Second Restated
                    Credit Agreement").
           10(b)* - 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(c)* - The Company's 1991 Management Options (incorporated by 
                    reference to Exhibit 4.1 to the Company's S-8 Registration
                    Statement (Reg. No. 33-43788)).
           10(d)* - The Company's 1992 Stock Incentive Plan (incorporated by
                    reference to Exhibit 4.3 to the Company's S-8 Registration
                    Statement (Reg. No. 33-48610)).
           10(e)* - The Company's 401(K) Plan (incorporated by reference to
                    Exhibit 10(i) to the Company's Form S-1 Registration
                    Statement (Reg. No. 33-43859)).
           10(f)  - Restructure Agreement dated February 25, 1991, among The
                    Aetna Casualty and Surety Company, Aetna Life Insurance
                    Company and the Company (incorporated by reference to
                    Exhibit 10(i) to the Company's Annual Report on Form 10-K
                    for the year ended December 31, 1990).
           10(g)  - Amended and Restated Agreement of Limited Partnership of
                    Plains Gulf Coast Limited Partnership dated February 25,
                    1991, (incorporated by reference to Exhibit 10(i) to the
                    Company's Annual Report on Form 10-K for the year ended
                    December 31, 1990).
           10(h)  - First Amendment to Second Restated Credit Agreement dated
                    as of September 15, 1994.

                                       36
<PAGE>
 
                     (incorporated by reference to Exhibit 10(k) to
                     the Company's Quarterly Report on Form 10-Q for the
                     quarterly period ended September 30, 1994).
            10(i)  - Second Amendment to Second Amended and Restated Credit
                     Agreement dated as of January 25, 1995, (incorporated by 
                     reference to Exhibit 10(k) to the Company's Annual Report
                     on Form 10-K for the year ended December 31, 1994).
            10(j) -  Third Amendment to Second Restated Credit Agreement dated 
                     as of June 12, 1995, (incorporated by reference to Exhibit
                     10(l) to the Company's Quarterly Report on Form 10-Q for
                     the calendar quarter ended June 30, 1995).
            10(k)  - Fourth Amendment to Second Restated Credit Agreement dated 
                     as of August 22, 1995, (incorporated by reference to
                     Exhibit 10(m) to the Company's Quarterly Report on Form 10-
                     Q for the calendar quarter ended September 30, 1995).
            10(l)  - Fifth Amendment to the Second Restated Credit Agreement 
                     dated as of December 20, 1995.
            10(m)  - Uncommitted Secured Transactional Line of Credit Facility
                     letter agreement dated as of August 23, 1995, between
                     Plains Marketing & Transportation Inc. and Internationale
                     Nederlanden (U.S.) Capital Corporation. 
            10(n)  - Uncommitted Secured Transactional Line of Credit Facility
                     letter agreement dated as of August 23, 1995 between PMCT
                     Inc. and Internationale Nederlanden (U.S.) Capital
                     Corporation. 
            11(a)  - Statement regarding computation of per share earnings for
                     the year ended December 31, 1995.
            11(b)  - Statement regarding computation of per share earnings for
                     the year ended December 31, 1994.
            11(c)  - Statement regarding computation of per share earnings for
                     the year ended December 31, 1993.
            21     - Subsidiaries of the Company.
            23     - Consent of Price Waterhouse LLP.
            27     - Financial Data Schedule.

*A management contract or compensation plan.
______________

     (b)  REPORTS ON FORM 8-K

               The Company filed a Current Report on Form 8-K dated December 22,
          1995, as amended by Amendment No. 1 thereto on Form 8-K/A reporting
          under Item 2 thereof the acquisition of the Illinois Basin Properties.
          Such Current Report included the following financial statements:

               AUDITED FINANCIAL STATEMENTS

               Report of Independent Accountants
               Statement of Revenues and Direct Operating Expenses for the years
                 ended December 31, 1992, 1993, and 1994, and the nine month
                 periods ended September 30, 1994 and 1995
               Notes to Statement of Revenues and Direct Operating Expenses

                                       37
<PAGE>
 
              PRO FORMA FINANCIAL INFORMATION (UNAUDITED)

              Pro Forma Financial Information
              Pro Forma Condensed Consolidated Balance Sheet as of September 30,
                  1995
              Pro Forma Condensed Consolidated Statement of Operations for the
                  year ended December 31, 1994
              Pro Forma Condensed Consolidated Statement of Operations for the
                  nine months ended September 30, 1995
              Notes to Pro Forma Condensed Consolidated Financial Statements

                                       38
<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 4, 1996             By: /s/ Phillip D. Kramer
                                    --------------------------------------------
                                    Phillip D. Kramer, 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 4, 1996             By: /s/ Greg L. Armstrong
                                    --------------------------------------------
                                    Greg L. Armstrong, President,
                                    Chief Executive Officer and Director
                                    (Principal Executive Officer)



Date: March 4, 1996             By: /s/ Robert A. Bezuch
                                    --------------------------------------------
                                    Robert A. Bezuch, Director



Date: March 4, 1996             By: /s/ Tom H. Delimitros
                                    --------------------------------------------
                                    Tom H. Delimitros, Director



Date: March 4, 1996             By: /s/ Cynthia A. Feeback
                                    --------------------------------------------
                                    Cynthia A. Feeback, Controller and Principal
                                    Accounting Officer (Principal Accounting
                                      Officer)



Date: March 4, 1996             By: /s/ William M. Hitchcock
                                    --------------------------------------------
                                    William M. Hitchcock, Director

                                       39
<PAGE>


 
Date: March 4, 1996             By: /s/ Phillip D. Kramer
                                    --------------------------------------------
                                    Phillip D. Kramer, Vice President and Chief
                                    Financial Officer (Principal Financial
                                    Officer)



Date: March 4, 1996             By: /s/ Dan M. Krausse
                                    --------------------------------------------
                                    Dan M. Krausse, Chairman of the Board and
                                    Director



Date: March 4, 1996             By: /s/ John H. Lollar
                                    --------------------------------------------
                                    John H. Lollar, Director



Date: March 4, 1996             By: /s/ D. Irving Obrow
                                    --------------------------------------------
                                    D. Irving Obrow, Director



Date: March 4, 1996             By: /s/ Robert V. Sinnott
                                    --------------------------------------------
                                    Robert V. Sinnott, Director



Date: March 4, 1996             By: /s/ J. Taft Symonds
                                    --------------------------------------------
                                    J. Taft Symonds, Director


     The Annual Report to Stockholders of the Company for the year ended
December 31, 1995, 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.

<PAGE>
 
<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, 1995 and 1994                F-3
 Consolidated Statements of Operations for the years ended
   December 31, 1995, 1994 and 1993                                          F-4
 Consolidated Statements of Cash Flows for the years ended
   December 31, 1995, 1994 and 1993                                          F-5
 Consolidated Statements of Changes in Stockholders' Equity
   for the years ended December 31, 1995, 1994 and 1993                      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, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1995, 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.


/s/ PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
Houston, Texas
February 22, 1996

                                      F-2
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES
                          CONSOLIDATED BALANCE SHEETS
                       (in thousands, except share data)
<TABLE>
<CAPTION>
                                                                                DECEMBER 31,
                                                                            ---------------------
                                                                              1995        1994
                                                                            ---------   ---------
<S>                                                                         <C>         <C>
                                        ASSETS
CURRENT ASSETS
Cash and cash equivalents                                                   $   6,129   $   1,291
Restricted cash                                                                    --       1,500
Accounts receivable                                                            51,632      32,306
Inventory                                                                       5,120       5,525
Prepaids and other                                                                751       1,064
                                                                            ---------   ---------
Total current assets                                                           63,632      41,686
                                                                            ---------   ---------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method:
      Subject to amortization                                                 328,712     265,123
      Not subject to amortization                                              48,795      35,779
Downstream assets, primarily crude oil terminal and storage facility           32,788      32,266
Other property and equipment                                                    7,789       6,090
                                                                            ---------   ---------
                                                                              418,084     339,258
Less allowance for depreciation, depletion and amortization                  (137,546)   (121,656)
                                                                            ---------   ---------
 
                                                                              280,538     217,602
                                                                            ---------   ---------
 
OTHER ASSETS                                                                    7,876       7,616
                                                                            ---------   ---------
 
                                                                            $ 352,046   $ 266,904
                                                                            =========   =========
 
                        LIABILITIES AND STOCKHOLDERS' EQUITY
 
CURRENT LIABILITIES
Accounts payable and other current liabilities                              $  56,573   $  36,282
Interest payable                                                                3,977       3,617
Royalties payable and drilling advances                                         6,364       4,702
Notes payable and other current obligations                                     1,467       1,550
                                                                            ---------   ---------
 
Total current liabilities                                                      68,381      46,151
 
BANK DEBT                                                                      98,000      45,100
SUBORDINATED DEBT                                                             100,000     100,000
OTHER LONG-TERM DEBT                                                            7,089       4,500
OTHER LONG-TERM LIABILITIES                                                     1,547       3,754
                                                                            ---------   ---------
 
                                                                              275,017     199,505
                                                                            ---------   ---------
 
SERIES C CUMULATIVE CONVERTIBLE PREFERRED STOCK,
   STATED AT LIQUIDATION PREFERENCE                                                --      20,937
                                                                            ---------   ---------
 
COMMITMENTS AND CONTINGENCIES (NOTE 10)
 
NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK
   AND OTHER STOCKHOLDERS' EQUITY
Preferred stock, stated at liquidation preference                                  --         481
Common stock, $.10 par value, 50,000,000 shares authorized; issued and      
 outstanding 16,178,670 shares at December 31, 1995, and 11,593,457
 shares at December 31, 1994                                                    1,618       1,159 
Additional paid-in capital                                                    118,090      89,274
Accumulated deficit                                                           (42,679)    (44,452)
                                                                            ---------   ---------
 
                                                                               77,029      46,462
                                                                            ---------   ---------
 
                                                                            $ 352,046   $ 266,904
                                                                            =========   =========
</TABLE>

                See notes to consolidated financial statements.

                                      F-3
<PAGE>
 
                    PLAINS RESOURCES INC. AND SUBSIDIARIES
                     CONSOLIDATED STATEMENTS OF OPERATIONS
                     (in thousands, except per share data)

<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                                ------------------------------
                                                                  1995      1994       1993
                                                                --------  --------  ----------
<S>                                                             <C>       <C>       <C>
REVENUE
Oil and natural gas sales                                       $ 64,080  $ 57,234   $ 57,507
Marketing, transportation and storage                            339,826   199,239    128,186
Interest and other income                                            319       223        335
                                                                --------  --------   --------
 
                                                                 404,225   256,696    186,028
                                                                --------  --------   --------
 
EXPENSES
Production expenses                                               30,256    27,220     28,285
Purchases, transportation and storage                            333,460   193,049    124,390
General and administrative                                         7,215     6,966      7,724
Depreciation, depletion and amortization                          17,036    16,305     16,980
Reduction of carrying cost of oil and natural gas properties          --        --     20,000
Interest expense                                                  13,606    12,585      8,847
                                                                --------  --------   --------
 
                                                                 401,573   256,125    206,226
                                                                --------  --------   --------
 
NET INCOME (LOSS)                                               $  2,652  $    571   $(20,198)
                                                                ========  ========   ========
 
Net income (loss) per common
  and common equivalent share                                       $.16      $.04     $(1.77)
                                                                ========  ========   ========
 
Weighted average number of common
  and common equivalent shares                                    15,981    11,625     11,438
                                                                ========  ========   ========
</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,
                                                                         --------------------------------
                                                                           1995       1994        1993
                                                                         ---------  ---------  ----------
 
CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                      <C>        <C>        <C>
Net income (loss)                                                        $  2,652   $    571    $(20,198)
Items not affecting cash flows from
 operating activities:                                        
 Depreciation, depletion and amortization                                  17,036     16,305      16,980
 Reduction of carrying cost of oil and natural gas properties                  --         --      20,000
Change in assets and liabilities resulting from operating activities:
 Accounts receivable                                                      (18,598)   (17,578)      2,010
 Inventory                                                                    405      8,050     (12,486)
 Prepaids and other                                                           106       (115)        389
 Accounts payable and other current liabilities                            14,133     11,119       1,231
 Interest payable                                                             347        503         357
 Royalties payable                                                            903       (486)      2,114
                                                                         --------   --------    --------
 
Net cash provided by operating activities                                  16,984     18,369      10,397
                                                                         --------   --------    --------
 
CASH FLOWS FROM INVESTING ACTIVITIES
Cash received for the sale of oil and gas properties                        7,355        314          --
Payment for acquisition, exploration and development costs                (71,250)   (39,885)    (52,826)
Payment for additions to other property and assets                         (1,120)    (2,130)    (23,625)
Proceeds from escrow account                                                  617      1,543          --
                                                                         --------   --------    --------
 
Net cash used in investing activities                                     (64,398)   (40,158)    (76,451)
                                                                         --------   --------    --------
 
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt                                               83,550     70,000      72,166
Proceeds from short-term debt                                                  --     10,576      12,682
Proceeds from sale of capital stock, options and warrants                     869     20,641         803
Principal payments of long-term debt                                      (30,650)   (60,500)    (36,566)
Principal payments of short-term debt                                          --    (20,214)     (3,044)
Payment of other long-term liabilities                                     (2,080)      (136)        (83)
Other                                                                         563     (1,070)     (1,270)
                                                                         --------   --------    --------
 
Net cash provided by financing activities                                  52,252     19,297      44,688
                                                                         --------   --------    --------
 
Net increase (decrease) in cash and cash equivalents                        4,838     (2,492)    (21,366)
Cash and cash equivalents, beginning of year                                1,291      3,783      25,149
                                                                         --------   --------    --------
 
Cash and cash equivalents, end of year                                   $  6,129   $  1,291    $  3,783
                                                                         ========   ========    ========
</TABLE>

                See notes to consolidated financial statements.

                                      F-5
<PAGE>
 
                     PLAINS RESOURCES INC. AND SUBSIDIARIES
           CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
                       (in thousands, except share data)

<TABLE>
<CAPTION>
                                                       $1.30 CUMULATIVE                ADDITIONAL                        
                                                         CONVERTIBLE                     PAID-IN   ACCUMULATED           
                                                       PREFERRED STOCK   COMMON STOCK    CAPITAL     DEFICIT             
                                         --------------------------------------------  ----------- -----------           
                                          SHARES    AMOUNT     SHARES       AMOUNT                             
                                         ---------  -------  ----------  ------------                          
<S>                                      <C>        <C>      <C>            <C>          <C>        <C>
BALANCE AT DECEMBER 31, 1992               48,770    $ 488   11,211,513     $1,121       $ 85,189   $(23,465)
                                                                                        
Conversion of $1.30 Cumulative                                                                               
 Convertible Preferred Stock                 (700)      (7)         620          2              6         -- 
                                                                                        
Capital stock issued in                                                                                      
 connection with an acquisition                --       --      215,137         21          1,111         -- 
                                                                                        
Capital stock issued upon exercise of                                                                        
 options and other                             --       --      139,743         13            905         -- 
                                                                                        
Dividends on $1.30 Cumulative                                                                                 
 Convertible Preferred Stock                   --       --           --         --             --       (189) 
                                                                                        
Net loss for the year                          --       --           --         --             --    (20,198)
                                         --------   ------   ----------     ------       --------   --------
BALANCE AT DECEMBER 31, 1993               48,070      481   11,567,013      1,157         87,211    (43,852)
                                                                                        
Warrant issued in connection                                                                                 
  with an acquisition                          --       --           --         --          2,000         -- 
                                                                                        
Preferred stock dividends                      --       --           --         --             --     (1,171)
                                                                                        
Capital stock issued upon exercise                                                                           
  of options and other                         --       --       26,444          2             63         -- 
                                                                                        
Net income for the year                        --       --           --         --             --        571
                                         --------   ------   ----------     ------       --------   --------
BALANCE AT DECEMBER 31, 1994               48,070      481   11,593,457      1,159         89,274    (44,452)
                                                                                        
Preferred stock dividends                      --       --           --         --             --       (879)
                                                                                        
Redemption of $1.30 Cumulative                                                                               
 Convertible Preferred Stock              (48,070)    (481)          --         --             --         -- 
                                                                                        
Conversion of Preferred Stock                  --       --    3,628,125        363         21,406         --
                                                                                        
Issuance of common stock in                                                                                  
  connection with an acquisition               --       --      798,143         80          6,447         -- 
                                                                                        
Capital stock issued upon exercise                                                                           
  of options and other                         --       --      158,945         16            963         -- 
                                                                                        
Net income for the year                        --       --           --         --             --      2,652
                                         --------   ------   ----------     ------       --------   --------
BALANCE AT DECEMBER 31, 1995                   --   $  --    16,178,670     $1,618       $118,090   $(42,679)
                                         ========   ======   ==========     ======       ========   ========
</TABLE>

                See notes to consolidated financial statements.

                                      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 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 the Los Angeles
Basin of California (the "LA Basin"), the Sunniland Trend of South Florida (the
"Sunniland Trend"), the Illinois Basin and the Gulf Coast area of Louisiana.
Its downstream 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 and the Gulf Coast area of Louisiana.

     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.  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 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 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 estimated present value of oil and natural gas reserves
reduced by future operating expenses, development expenditures and abandonment
costs (net of salvage values), and income taxes (the "Standardized Measure")
(see Note 15).

                                      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.  Approximately $1.6 million of interest was capitalized
during 1993 in connection with the construction of the Cushing Terminal.

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, 1995 and 1994, in the amount of $3.4 million and $4.2 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 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
enacted tax rates in effect for the year in which the differences are expected
to reverse.

MARKETING AND TRANSPORTATION

     The Company's marketing activities are conducted through its wholly-owned
subsidiary, Plains Marketing & Transportation Inc. ("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.  The Company's policy is to only purchase crude
oil for which it has a market to sell and to negotiate its sales contracts so
that fluctuations in prices do not affect the gross margin which it receives.

HEDGING

     The Company periodically uses certain instruments to hedge its exposure to
price fluctuations on oil and natural gas transactions.  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.  The Company has entered into an interest rate swap to manage
the interest rate exposure on certain of its long-term debt.  The amount to be
paid or received from the interest rate swap is charged or credited to interest
expense over the term of the swap.

STOCK OPTIONS

     In October 1995, the Financial Accounting Standards Board issued Statement
No. 123 ("SFAS 123"), "Accounting for Stock Based Compensation".  As permitted
by SFAS 123, the Company plans to continue to retain its current method of
accounting for stock compensation and adopt the disclosure of this Statement in
1996.

                                      F-8
<PAGE>
 
NOTE 2 -- INVENTORY
-------------------
 
Inventory consists of the following:

                                          DECEMBER 31,
                                        ----------------
                                          1995     1994
                                         ------   ------
                                         (in thousands)
      Crude oil                          $2,884   $3,901
      Materials and supplies              2,236    1,624
                                         ------   ------
                                         $5,120   $5,525
                                         ======   ======

Substantially all of the crude oil inventory at December 31, 1995 and 1994,
except for minor amounts of working inventory, was hedged with New York
Mercantile Exchange ("NYMEX") futures contracts or short-term physical delivery
contracts.  Deferred gains or losses from inventory hedges are included as part
of the inventory cost and recognized when the related inventory is sold.
 
NOTE 3 -- LONG-TERM DEBT
------------------------
 
Long-term debt consists of the following:
                                                    DECEMBER 31,
                                                --------------------
                                                  1995        1994
                                                --------    --------
                                                  (in thousands)
Revolving Credit Facility, bearing interest     
 at weighted average interest rates of
 8.2% and 7.9%, at December 31, 1995
 and 1994, respectively                         $ 56,000    $ 45,100  
Illinois Basin Acquisition Indebtedness,        
 bearing interest at 7.35% 
 at December 31, 1995                             42,000          -- 
12% Senior Subordinated Notes due 1999           100,000     100,000
Other long-term debt                               8,533       6,000
                                                --------    --------
 Total long-term debt                           $206,533    $151,100
 Less current maturities                          (1,444)     (1,500)
                                                --------    --------
                                                $205,089    $149,600
                                                ========    ========

REVOLVING CREDIT FACILITY

     The Company maintains a revolving credit facility (the "Revolving Credit
Facility") with a group of five banks (collectively the "Lenders").  In December
1995, the total credit commitment and borrowing base under the Revolving Credit
Facility was increased to $75 million from $65 million.  The Revolving Credit
Facility is guaranteed by all of the Company's subsidiaries other than PMCT,
Inc. ("PMCT") and such guarantees are secured by all of the Company's oil and
natural gas properties (except Plains Illinois Inc. ("Plains Illinois")) and the
stock of such subsidiaries.  The Cushing Terminal is not pledged as security for
any of the Company's debt.  The Revolving Credit Facility 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 1/2% per annum on the unused portion of the borrowing
base.

     The Revolving Credit Facility, as amended, consists of a $75 million
revolving credit loan which matures on October 1, 1997, at which time the credit
commitment reduces by an amount equal to one-third of the then outstanding
principal amount of the revolving credit loan.  The remaining outstanding
balance converts to a term loan which is repayable in equal installments due on
January 1, 1998, and April 1, 1998.  The Revolving Credit Facility bears
interest at the option of the Company at (i) LIBOR plus 2% or (ii) the higher of
the Base Rate (as defined in the Revolving Credit Facility) plus 5/8% or the
federal funds rate plus 1 1/8%.  Borrowings in excess of $65 million bear
interest at an additional 1/2% through December 31, 1996, and an additional 1%
thereafter.

     The Revolving Credit Facility contains covenants which, among other things,
restrict 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>
 
ILLINOIS BASIN ACQUISITION INDEBTEDNESS

     On December 22, 1995, Plains Illinois, a wholly owned subsidiary of the
Company, acquired, effective November 1, 1995, all of the upstream oil and gas
assets of Marathon Oil Company ("Marathon") in the Illinois Basin (the "Illinois
Basin Properties").  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 the Company's common
stock (the "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 a four year $42 million credit
facility (the "Illinois Basin Acquisition Indebtedness") under a credit
agreement between Plains Illinois and three banks.

     The Illinois Basin Acquisition Indebtedness consists of a $42 million four-
year term loan with a final maturity on December 22, 1999.  Monthly payments of
interest and principal are required from 85% of Field Level Net Revenues, as
defined in the Illinois Basin Acquisition Indebtedness.  Field Level Net
Revenues are defined as revenues derived from the sale of production from the
Illinois Basin Properties less a predefined amount of production expense equal
to the Company's original projections of such expenses, or actual production
expense, whichever is less, on a monthly basis.  The Illinois Basin Acquisition
Indebtedness bears interest at LIBOR plus 2% through September 30, 1996, and
LIBOR plus 3%, thereafter.  The Company has entered into a one year interest
rate swap agreement with one of the lending banks to fix the LIBOR portion of
the interest rate at 5.35%.

     The Illinois Basin Acquisition Indebtedness is secured by a first lien on
the Illinois Basin Properties and contains covenants which, among other things
prohibit (i) Plains Illinois from making certain loans and investments, and (ii)
additional indebtedness by Plains Illinois.

12% SENIOR SUBORDINATED NOTES DUE 1999

     On October 2, 1992, the Company sold at par $100 million of 12% Senior
Subordinated Notes (the "12% Notes") due October 1, 1999.  The 12% Notes are
redeemable, at the option of the Company, at 106% of the principal amount
through October 1, 1996, and thereafter at prices declining annually to 100% of
principal at October 1, 1998, plus accrued and unpaid interest to the date of
redemption.  A sinking fund payment of $50 million calculated to retire 50% of
the issue is due October 1, 1998.  The indenture under which the 12% Notes were
issued (the "Indenture") contains, among other things, limitations on additional
borrowings in excess of certain amounts and limitations on Restricted Payments,
as defined in the Indenture, including cash dividends on the Common Stock.  In
the event of a change of control, as defined in the Indenture, the Company will
be required to make an offer to repurchase the 12% Notes at 101% of the
principal amount thereof, plus accrued and unpaid interest to the date of
repurchase.  The 12% 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.  The 12% Notes are guaranteed by all of the
Company's principal subsidiaries, with the exception of PMCT, a wholly-owned,
sole purpose subsidiary of the Company (see Note 4), and PLX Crude Lines Inc.
("PLX Crude").  Such guarantees may be released under certain circumstances.

OTHER LONG-TERM DEBT

     Included in other long-term debt at December 31, 1995 is (i) $4.6 million
related to the 1995 acquisition of a production payment burdening certain of the
Company's LA Basin properties and (ii) $3.9 million related to the 1991 purchase
of a portion of the limited partners' interest in a partnership in which the
Company is the general partner.  Such amounts have maturities of approximately
$1.4 million in 1996, $2 million in 1997 and 1998, and approximately $500,000
per year in each of the years 1999 through 2004.

     The aggregate amount of maturities of all long-term indebtedness for the
next five years is:  1996 - $1.4 million, 1997 - $2 million, 1998 - $108
million, 1999 - $92.5 million and 2000 - $.5 million.

NOTE 4 -- UNCOMMITTED SECURED TRANSACTIONAL GUIDANCE FACILITY
-------------------------------------------------------------

     During 1995, Plains Marketing established an $80 million Uncommitted
Secured Demand Transactional Line of Credit (the "Transactional Facility") with
three 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

                                      F-10
<PAGE>
 
Marketing 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.  At December 31, 1995, approximately $49.1
million in letters of credit were outstanding under the Transactional Facility.

     PMCT, a wholly owned subsidiary of the Company, has established a $20
million sublimit (the "Sublimit") within the Transactional Facility for standby
letters of credit and 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.  Standby letters of credit
and borrowings under the Sublimit are secured by all of the assets of PMCT and
are recourse only to PMCT.  At December 31, 1995, no letters of credit or
borrowings were outstanding under the Sublimit.

     Letters of credit under the Transactional Facility are generally issued for
up to seventy day periods and bear fees of 1.5% per annum.  Borrowings incur
interest at the option of the borrower at (i) the Base Rate, as defined, plus
5/8% or (ii) LIBOR plus 2%.  All financings under the Transactional Facility,
which expires in August 1996, are at the discretion of the lenders.  Aggregate
cash borrowings by both subsidiaries are limited to $20 million.

NOTE 5 -- CAPITAL STOCK
-----------------------

     The Company has authorized capital stock consisting of 50,000,000 shares of
Common Stock, $.10 par value, and 2,000,000 shares of preferred stock, $1.00 par
value.  At December 31, 1995, there were 16,178,670 shares of Common Stock
issued and outstanding and no shares of preferred stock outstanding.

STOCK WARRANTS

     At December 31, 1995, the Company had warrants outstanding which entitle
the holders thereof to purchase an aggregate 950,000 shares of Common Stock.
Per share exercise prices for the warrants are as follows: 100,000 shares at
$9.25; 100,000 shares at $7.50 and 750,000 shares at $6.00.  These warrants
expire at various times from 1997 to 2000.

$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

     In July 1994, the Company sold in a private placement 200,000 shares of its
Series C Cumulative Convertible Preferred Stock (the "Series C Preferred Stock")
for net proceeds of approximately $20 million.  On January 2, 1995, the Company
paid a dividend on 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 9,370 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.  As a result of this conversion and the redemption of
the $1.30 Preferred Stock, all outstanding preferred stock has been eliminated.

     Proceeds from the Series C Preferred Stock were used to repay the $11.5
million bridge loan incurred to finance the acquisition of a 50% working
interest in six producing oil fields in the Sunniland Trend of South Florida
(the "Sunniland Trend Properties") (see Note 9), to fund the exploitation of
such properties and to reduce the amount outstanding on the Revolving Credit
Facility.

                                      F-11
<PAGE>
 
STOCK OPTIONS

     Stock option transactions for 1995 and 1994 are summarized below:

<TABLE>
<CAPTION>
                                                1995                       1994
                                    --------------------------   --------------------------
                                      SHARES     OPTION PRICE     SHARES      OPTION PRICE
                                    ---------   --------------   ---------   --------------
 
<S>                                 <C>         <C>              <C>         <C>
Outstanding at beginning of year    1,518,991   $5.00 to $15.63  1,641,971   $5.00 to $15.63
Granted                               365,250   $6.25                  --
Exercised                            (146,945)  $5.00 to $6.75     (19,188)  $5.00
Canceled or expired                    (9,493)  $5.25 to $6.75    (103,792)  $5.00 to $10.50
                                    ---------                    ---------
Outstanding at end of year          1,727,803   $5.00 to $15.63  1,518,991   $5.00 to $15.63
                                    =========                    =========
Exercisable at end of year          1,233,216   $5.00 to $15.63  1,201,767   $5.00 to $15.63
                                    =========                    =========
</TABLE>

     The Company has options outstanding under its 1992 Stock Incentive Plan,
under which a maximum of 1.1 million shares of Common Stock were reserved for
issuance, and options outstanding outside of the plan which were granted in 1991
to certain officers and employees and a director.  Generally, terms of the
options provide for an exercise price of not less than market at date of grant,
a pro rata vesting period of two to four years and an exercise period of six to
ten years.

NOTE 6 -- EARNINGS PER SHARE
----------------------------

     Primary earnings per share is based on the weighted average number of
common and common equivalent shares of Common Stock outstanding.  Common
equivalent shares include employee stock options and warrants when dilutive.
Fully diluted earnings per share is based on the weighted average number of
common and common equivalent shares in addition to all other convertible
securities, when dilutive.  The assumed conversion of these securities was not
dilutive for all periods presented and, accordingly, is not reflected herein.
For purposes of the earnings per share calculation, Common Stock issued upon the
conversion of the Series C Preferred Stock is included in the weighted average
number of shares outstanding effective January 1, 1995.  Additionally, 1994
earnings per share includes the dilutive effect of additional shares of Series C
Preferred Stock issued in 1995 as payment of 1994 accrued dividends (See Note
5).

NOTE 7 -- INCOME TAXES
----------------------

     The Company's deferred income tax assets (liabilities) at December 31, 1995
and 1994 consist of the tax effect of income tax carryforwards and differences
related to the timing of recognition of certain acquisition, exploration, and
development costs for financial and tax reporting as follows:

<TABLE>
<CAPTION>
                                                        DECEMBER 31,
                                                    -------------------
                                                      1995       1994
                                                    --------   --------
                                                       (in thousands)
<S>                                                 <C>        <C>
Deferred tax assets:
  Tax credit carryforwards                          $    988   $  1,035
  Percentage depletion carryforward                    2,380      2,380
  Net operating loss ("NOL") carryforwards            55,798     46,120
                                                    --------   --------
                                                      59,166     49,535
Deferred tax liabilities:
  Acquisition, exploration and development costs     (40,871)   (28,975)
                                                    --------   --------
  Net deferred tax asset                              18,295     20,560
  Valuation allowance                                (18,295)   (20,560)
                                                    --------   --------
                                                    $  --      $  --
                                                    ========   ========
</TABLE>

     The realization of the deferred tax asset is dependent on the Company's
ability to generate taxable earnings in future periods.  A valuation allowance
for $18.3 million has been recorded at December 31, 1995, to reflect the
estimated amount of the deferred tax asset which may not be realized due to the
expiration of a portion of the NOL's and tax credit carryforwards.  The net
change in the current year deferred tax asset and related valuation allowance
was a decrease of $2.3 million.  The decrease was primarily attributable to the
expiration of certain NOL carryforwards.

                                      F-12
<PAGE>
 
     Future realization of the tax asset will be affected by recent additions to
the Company's oil and natural gas reserves and the resulting increases in
anticipated future income. Management is currently reassessing the ability to
realize a portion of such asset based on these reserve additions.

     At December 31, 1995, the Company had carryforwards of approximately $164.1
million of regular tax NOL's, $7.0 million of statutory depletion, $.8 million
of investment tax credit ("ITC") and $.2 million of alternative minimum tax
("AMT") credit.  Of these amounts, utilization of approximately $22.9 million of
the NOL carryforwards and $.5 million of the ITC carryforward is limited to
certain companies within the consolidated group. At December 31, 1995, the
Company had approximately $149.4 million of AMT NOL carryforwards available as a
deduction against future AMT income. The NOL carryforwards expire from 1996
through 2010.

     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
Operations:

<TABLE>
<CAPTION>
                                                        DECEMBER 31,
                                                       ---------------
                                                        1995     1994
                                                       -------  ------
<S>                                                    <C>      <C>
                                                       (in thousands)
U.S. federal income tax provision at statutory rate     $ 902   $ 194
Utilization of tax attributes previously included        (902)   (194)
  in allowance and other                                -----   -----
 
                                                       $  --    $  --
                                                       ======   =====
</TABLE>

     Although the Company recorded net income for the year 1995 and 1994, no
provision for income taxes was reflected but rather the valuation allowance
discussed above was adjusted.

     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 Final
Treasury Regulations issued by the Internal Revenue Service, the Company does
not believe that an Ownership Change has occurred as of December 31, 1995.

NOTE 8 -- RELATED PARTY TRANSACTIONS
------------------------------------

     In April 1993, the Company purchased certain oil and natural gas properties
and associated participation rights from an officer and two directors, one of
which is also an officer, for approximately $1.4 million.  The purchase price
consisted of 215,137 restricted shares of Common Stock, valued at approximately
$1.1 million, and the assumption of approximately $255,000 of net liabilities.

NOTE 9 -- ACQUISITIONS AND DISPOSITIONS
---------------------------------------

     As further discussed in Note 3, effective November 1, 1995, the Company
purchased the Illinois Basin Properties for approximately $51.5 millon.  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.

     The following unaudited information reflects pro forma results of
operations as if the acquisition occurred on January 1, 1995:

<TABLE>
<CAPTION>
                                                          YEAR ENDED
                                                       DECEMBER 31, 1995
                                                     ---------------------
                                                     HISTORICAL  PRO FORMA
                                                     ----------  ---------
<S>                                                    <C>        <C>
Revenue (in thousands)                                 $404,225   $426,294
Net income (in thousands)                              $  2,652   $  9,589
Net income per common and common equivalent share      $   0.16   $   0.57
</TABLE>

                                      F-13
<PAGE>
 
     In December 1995, Stocker Resources Inc. ("Stocker"), a wholly-owned
subsidiary of the Company, acquired from Chevron U.S.A. ("Chevron") a production
payment burdening certain of Stocker's LA Basin 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 LA Basin properties and
approximately ten acres of surface fee lands 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, provided
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 1995, the Company sold certain non-strategic oil and natural gas
properties located primarily in the Gulf Coast area of Texas and Louisiana for
net proceeds of approximately $7.4 million.

     During the first quarter of 1993, the Company acquired all of the
outstanding capital stock of Calumet Florida, Inc. ("CFI") for approximately $5
million, including transaction costs.  CFI, organized in February 1993, owned
and operated a 50% working interest in the Sunniland Trend Properties which it
acquired from Exxon just prior to its acquisition by the Company.  The Company
funded the acquisition primarily through the Revolving Credit Facility.

     During 1994, CFI 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.  Operating results from the additional 50%
interest in the Sunniland Trend Properties are included in the accompanying
financial statements effective May 1, 1994.  The aggregate purchase price,
including acquisition costs, was approximately $13.6 million including the
issuance of a five year warrant to purchase 750,000 shares of Common Stock at an
exercise price of $6.00 per share.  The acquisition was initially financed by an
$11.5 million bridge loan which was repaid in July 1994 with proceeds from the
sale of the Series C Preferred Stock (see Note 5).

     In October 1993, the Company purchased an average 46% nonoperated working
interest in certain natural gas properties for approximately $2.7 million.  The
acquisition consisted of 47 producing wells and surrounding acreage located in
the San Arroyo Field in northeastern Utah.  At the acquisition date, these
properties added approximately 14 billion cubic feet of natural gas to the
Company's proved reserves.  The Company funded the acquisition primarily through
the Revolving Credit Facility.

     In late 1993, the Company acquired all of Texaco Exploration and Production
Inc.'s interest in the Vickers lease, which is located immediately adjacent to
one of the Company's existing LA Basin fields, for approximately $5 million.

     In connection with Stocker's acquisition of certain of the LA Basin
properties from Chevron in 1990 (the "Stocker Properties"), numerous disputes
arose regarding each party's obligations under the purchase and sale agreement
governing such transaction.  These disputes included, among other things, the
financial responsibility for a 2.8% nonoperating working interest in a high
volume but marginal property.  In December 1993, the parties entered into a
partial settlement under which Chevron agreed to terminate an agreement with
respect to such property and to assume financial responsibility therefor.  Set
forth below is a summary of the pro forma impact of this termination on selected
items for the year ended December 31, 1993.

<TABLE>
<CAPTION>
                                  YEAR ENDED DECEMBER 31,
                              ---------------------------------
                                           1993
                              ---------------------------------
                                 HISTORICAL          PRO FORMA
                                ------------        -----------
                              (IN THOUSANDS, EXCEPT UNIT PRICES)
<S>                                <C>               <C>
Production volumes, BOE               4,252             3,989
Production expense per BOE         $   6.65          $   6.24
Net loss                           $(20,198)         $(20,198)
</TABLE>

                                      F-14
<PAGE>
 
NOTE 10 -- COMMITMENTS AND CONTINGENCIES
----------------------------------------

     Minimum commitments in connection with office space and computer and
trucking equipment leased by the Company are:  1996 - $1 million; 1997 through
1999 - $.9 million annually;  thereafter - $.8 million.  Rental payments made
under the terms of similar arrangements totaled approximately $1.2 million in
each of the three years ended December 31, 1995, 1994 and 1993.

     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, 1995,
Plains Marketing had outstanding letters of credit of approximately $49.1
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 270.  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 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.

     Although the Company obtained environmental studies on its properties in
the LA Basin, 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 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 the Stocker 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 $14 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 1995, 1994 and 1993 include $1 million, $1.1 million
and $1.8 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 15.

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

                                      F-15
<PAGE>
 
     The Company and certain of its subsidiaries are the general partners of
various limited partnerships. Accordingly, the Company and its subsidiaries as
general partner have unlimited liability with respect to the operations of the
partnerships.

NOTE 11 -- LITIGATION
---------------------

     On April 27, 1992, the Company and certain of its officers and directors
and a former director and officer were named as defendants in a lawsuit filed in
the United States District Court for the Southern District of Texas captioned
Judith Rubinstein and Howard Greenwald v. Collins, et al., C.A. No. H-92-1297.
The complaint brings a class action (the class period of which is October 23,
1991, through April 13, 1992) for, among other things, alleged violations of
Sections 10(b) and 20(a) of the Exchange Act and for state law fraud and
negligent misrepresentation, arising out of certain alleged misrepresentations
and omissions in the Company's disclosures regarding its onshore natural gas
exploration activities.  The plaintiffs, who purport to have purchased their
Common Stock in open market transactions (300 and 375 shares, respectively),
contend the class is entitled to approximately $30 million for compensatory
damages and punitive damages in an unspecified amount.  The Company filed a
motion to dismiss in July 1992.  On August 24, 1992, the Court entered an Order
of Dismissal and a Final Judgment dismissing the plaintiffs' complaint for
failure to state a claim under the federal securities laws and/or under the
common law of the State of Texas.  On September 10, 1992, the plaintiffs filed a
Notice of Appeal of the District Court's judgment with the United States Court
of Appeals for the Fifth Circuit (No. 92-2736).  On May 5, 1994, the Fifth
Circuit Court ruled, among other things, that the plaintiffs had sufficiently
pleaded claims under the federal securities laws and under Texas common law and
reversed the trial court's dismissal and remanded the case to the trial court
for further proceedings.

     On July 27, 1993, a second case similar to the Rubinstein case described in
the preceding paragraph was filed in the United States District Court for the
Southern District of Texas captioned Gloria Moroson v. Collins, et al., C.A. No.
H-93-2305, naming the Company and certain of its officers and directors and a
former director and officer as defendants.  The complaint brings a class action
(the class period of which is May 11, 1992, through August 14, 1992) for, among
other things, alleged violations of Sections 10(b) and 20(a) of the Exchange Act
and for state law fraud and negligent misrepresentation, arising out of certain
alleged misrepresentations and omissions in the Company's disclosures regarding
its onshore natural gas exploration activities.  The plaintiff, who purports to
have purchased 50 shares of Common Stock in an open market transaction, contends
the class is entitled to approximately $60 million for compensatory damages and
punitive damages in an unspecified amount.  These amounts are alleged to be in
addition to the damages claimed in the Rubinstein case.  In June 1994, the trial
court granted the Company's motion to consolidate the Rubinstein and Moroson
cases.

     On February 20, 1996, the Court denied the Company's motion for summary
judgment in these two cases and set a trial date for May 8, 1996. The Company
expects the cases to go to trial before a jury on or or about such date.
Although the Company believes these complaints to be without merit and intends
to vigorously defend these lawsuits, if the plaintiffs were awarded, and the
Company were ultimately required to pay, a substantial portion of the $90
million in compensatory damages sought by the plaintiffs, it would have a
material adverse effect on the Company.

     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, CFI, 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 lands underlying this unitized field, CFI 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 CFI
as a counter-defendant.  No trial date has been set in this case.  Exxon and CFI
have filed a motion to dismiss the counterclaims. The Court has not yet ruled on
such motion.  CFI believes the counterclaim challenging the validity of certain
oil and natural gas leases owned by CFI to be without merit and intends to
vigorously defend against such claim.

                                      F-16
<PAGE>
 
     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 12 -- MAJOR CUSTOMERS
--------------------------

     Phibro Division of Salomon Inc. ("Phibro") and Phibro Energy USA, Inc.,
accounted for 16% and 12%, respectively, of the Company's total revenue
(exclusive of interest and other income) during 1995.  Customers accounting for
more than 10% of total revenue for 1994 and 1993 were as follows:  1994 --
Phibro -- 19% and Chevron -- 16%; 1993 -- Chevron -- 23%, Marathon -- 22% and
Phibro --15%.  No other single purchaser of the Company's products accounted for
as much as 10% of total sales during 1995, 1994 and 1993.  During 1995, 1994 and
1993, Chevron accounted for 39%, 71% and 76% of the Company's oil and natural
gas sales, respectively. Additionally during 1995, Unocal and Scurlock Permian
Corporation accounted for approximately 28% and 19%, respectively, of the
Company's oil and natural gas sales.  During 1995, Unocal was the purchaser of
the Company's LA Basin oil production, while Scurlock Permian Corporation was
purchaser of oil production attributable to the Sunniland Trend Properties.

NOTE 13 -- 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
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.

     The Company has entered into crude oil financial swap arrangements to fix
the NYMEX WTI index price for a significant portion of its crude oil production.
On December 31, 1995, these arrangements provided for a NYMEX WTI indexed
average price for:  (i) 11,000 barrels per day through March 31, 1996, at $18.07
per barrel; (ii) 10,000 barrels per day from April 1, 1996, through May 31,
1996, at $18.03 per barrel; (iii) 9,500 barrels per day from June 1, 1996,
through June 30, 1996, at $18.01 per barrel; (iv) 3,500 barrels per day from
July 1, 1996, through December 31, 1996, at $17.48 per barrel; and (v) 1,500
barrels per day from January 1, 1997, through June 30, 1997, at $17.23 per
barrel.  The Company has entered into additional swap arrangements which provide
for a NYMEX WTI indexed ceiling price of $17.63 per barrel and a floor price of
$16.50 per barrel for 3,000 barrels per day from July 1, 1996, through December
31, 1996.  Location and quality differentials attributable to the Company's
properties are not included in the foregoing prices.  The crude oil swap
agreements provide for monthly settlement based on the differential between the
contract price and the actual NYMEX WTI crude oil price.  The arrangements do
not expose the Company to any basis risk.  Gains or losses on the crude oil
swaps are recognized in the month of related production and are included in oil
and natural gas sales.

CONCENTRATION OF CREDIT RISK

     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 and exploration and production companies which own interests in
properties operated by the Company. 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.

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

                                      F-17
<PAGE>
 
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,
                                       ----------------------------------------
                                              1995                1994
                                       -------------------  -----------------
                                       CARRYING    FAIR     CARRYING    FAIR
                                        AMOUNT     VALUE     AMOUNT     VALUE
                                       --------  ---------  --------  ---------
                                                   (IN THOUSANDS)
<S>                                    <C>       <C>        <C>        <C>
LIABILITIES:
  Bank debt                            $ 98,000  $ 98,000   $ 45,100   $45,100
  Subordinated debt                     100,000   105,250    100,000    99,000
  Other long-term debt (see Note 3)       8,533     8,624      4,500     3,873
SERIES C PREFERRED STOCK                     --        --     20,937    20,937
OFF BALANCE SHEET FINANCIAL
 INFORMATION:
  Unrealized loss on crude oil              
    swap agreements                          --    (5,438)        --    (1,204)
</TABLE>

     The carrying value of bank debt approximates its fair value as interest
rates are variable, based on prevailing market rates.  The fair value of
subordinated debt was based on quoted market prices.  Other long-term debt was
valued by discounting the future payments using the Company's incremental
borrowing rate.  The fair value of the Series C Preferred Stock is estimated to
be its liquidation value at December 31, 1994.  The fair value of the crude oil
swap agreements is the estimated amount that the Company would pay or receive as
if the agreements had terminated at December 31, 1995 and 1994, based on the
closing prices for NYMEX futures contracts on such dates.

NOTE 14 --  SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
-------------------------------------------------------------

     Selected cash payments and noncash activities were as follows:

<TABLE>
<CAPTION>
                                                   YEAR ENDED DECEMBER 31,
                                                ------------------------------
                                                  1995       1994       1993
                                                ---------  ---------  --------
                                                       (IN THOUSANDS)
<S>                                             <C>        <C>        <C>
Cash paid for interest (net of amount
 capitalized)                                    $13,259    $12,082   $ 8,489
                                                 =======    =======   =======
 
Noncash investing and financing activities:
  Series C Preferred Stock Dividends             $  --      $   937   $  --
                                                 =======    =======   =======
  Conversion of Series C Preferred               $21,769    $  --     $  --
                                                 =======    =======   =======
 
Detail of properties acquired for other than
  cash:
  Fair value of acquired assets                  $56,100    $13,600   $ 7,387
  Debt issued and liabilities assumed             (4,600)        --    (6,255)
  Capital stock and warrants issued               (6,527)    (1,250)   (1,132)
                                                 -------    -------   -------
  Cash paid                                      $44,973    $12,350   $  --
                                                 =======    =======   =======
</TABLE>

                                      F-18
<PAGE>
 
NOTE 15 -- OIL AND NATURAL GAS ACTIVITIES
-----------------------------------------

COSTS INCURRED

The Company's oil and natural gas acquisition, exploration and development
activities are primarily 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,
                               ----------------------------
                                 1995      1994      1993
                               --------  --------  --------
<S>                             <C>       <C>       <C>
                                   (IN THOUSANDS)
Property acquisition costs:
   Unproved properties          $18,136   $ 6,150   $ 4,800
   Proved properties             41,194    13,222    19,659
Exploration costs                 2,001     5,907    10,524
Development costs                22,681    15,570    26,786
                                -------   -------   -------
                                $84,012   $40,849   $61,769
                                =======   =======   =======
</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 and development activities, and the aggregate related DD&A.

<TABLE>
<CAPTION>
                                  DECEMBER 31,
                             ----------------------
                                1995        1994
                             ----------  ----------
                                (IN THOUSANDS)
        <S>                  <C>         <C>
        Proved properties    $ 328,712   $ 265,123
        Accumulated DD&A      (131,063)   (116,430)
                             ---------   ---------
                             $ 197,649   $ 148,693
                             =========   =========
</TABLE>

     Under full cost accounting rules, to the extent that the Standardized
Measure of the proved reserves (as described below) is less than the amount of
net capitalized costs of proved properties, a write-down is required.  The
capitalized costs of the Company's proved oil and natural gas properties
exceeded the Standardized Measure by approximately $20 million at year-end 1993
due to low crude oil prices and accordingly, the capitalized costs were written
down by such amount.  The DD&A rate per equivalent unit of production excluding
the write-down was $3.02, $3.17 and $3.57 for the three years ended December 31,
1995, 1994 and 1993, respectively.  The DD&A rate per equivalent unit of
production for 1993 including the noncash writedown of the recorded cost of the
Company's oil and natural gas properties was $8.27.

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,
                                ------------------
                                  1995      1994
                                --------  --------
                                  (IN THOUSANDS)
        <S>                      <C>       <C>
        Acquisition costs        $35,550   $23,830
        Exploration costs          5,075     5,470
        Capitalized interest       8,170     6,479
                                 -------   -------
                                 $48,795   $35,779
                                 =======   =======
</TABLE>

     Unproved properties not subject to amortization at December 31, 1995,
consist mainly of 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%, 16% and 24% of
the balance in unproved properties at December 31, 1995, related to additions
made in 1995, 1994, and 1993, respectively.

                                      F-19
<PAGE>
 
     During 1995, 1994 and 1993, the Company capitalized $3.1 million, $2.7
million and $2.7 million, respectively, of interest related to costs of unproved
property 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, 1995.  The
following reserve information  is based upon reports of the independent
petroleum consulting firms of H.J. Gruy and Company with respect to the LA Basin
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 (the "SEC").

     In management's opinion, the reserve estimates presented herein, in
accordance with generally accepted engineering and evaluation principles
consistently applied, are believed to be reasonable.  However, there are
numerous uncertainties inherent in estimating quantities and values of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond 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.

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,
1995.

<TABLE>
<CAPTION>
                                           AS OF OR FOR THE YEAR ENDED DECEMBER 31,
                                     ---------------------------------------------------
                                           1995            1994                1993
                                     ---------------   ---------------   ---------------
                                       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                    61,459   51,009   38,810   49,397   33,390   39,861
Revisions of previous estimates       5,423    2,792   16,834    4,365   (6,478)  (7,753)
Extensions, discoveries, improved
 recovery and other additions        15,489    1,730    4,362    1,182    3,712    6,250
 
Sale of reserves in-place            (1,227)  (9,773)     (16)    (446)     (92)    (622)
Purchase of reserves in place        17,640      130    5,304       80   11,834   15,837
Production                           (4,376)  (2,778)  (3,835)  (3,569)  (3,556)  (4,176)
                                     ------   ------   ------   ------   ------   ------

Ending balance                       94,408   43,110   61,459   51,009   38,810   49,397
                                     ======   ======   ======   ======   ======   ======
 
PROVED DEVELOPED RESERVES
Beginning balance                    48,978   30,869   30,646   28,436   24,296   20,555
                                     ======   ======   ======   ======   ======   ======
Ending balance                       67,266   29,397   48,978   30,869   30,646   28,436
                                     ======   ======   ======   ======   ======   ======
</TABLE>

                                      F-20
<PAGE>
 
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,
                                       ------------------------------------
                                           1995         1994        1993
                                       ------------  ----------  ----------
                                                 (in thousands)
<S>                                     <C>          <C>         <C>
Future cash inflows                     $1,513,145   $ 894,434   $ 497,942
Future development costs                  (107,995)    (62,695)    (44,644)
Future production expense                 (692,009)   (414,741)   (221,814)
                                        ----------   ---------   ---------
Future net cash flows
  (before income taxes)                    713,141     416,998     231,484
Discounted at 10% per year                (346,361)   (187,627)    (96,945)
                                        ----------   ---------   ---------
Standardized measure of
   discounted future net cash              366,780     229,371     134,539
   flows (before income taxes)
Discounted future income                   (61,939)    (26,427)     (4,050)
   tax expense                          ----------   ---------   ---------
 
Standardized measure of                 $  304,841   $ 202,944   $ 130,489
   discounted future net cash flows     ==========   =========   =========
</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 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, 1995, is based on the price for NYMEX WTI
     crude oil of $19.55 per barrel ($18 per barrel WTI posted price) with
     variations therefrom based on location and grade of crude oil. The Company
     has entered into financial swap arrangements to fix the price on a
     significant portion of its crude oil production. These prices are included
     in the reserve reports through the term of the arrangements (See Note 13).
     The overall average prices as of December 31, 1995, were $15.55 per barrel
     of crude oil, condensate and natural gas liquids and $1.05 per Mcf of
     natural gas.

3.   The future gross revenue streams were reduced by estimated future operating
     costs (including production and ad valorem taxes) and future development
     and abandonment costs, all of which were based on current costs.

4.   SFAS No. 69 requires the Company further to 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.

                                      F-21
<PAGE>
 
     The principal sources of changes in the standardized measure of future net
cash flows for the three years ended December 31, 1995, are as follows:

<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                            ---------------------------------------------
                                               1995           1994             1993
                                            ----------  ----------------  ---------------
                                                           (in thousands)
<S>                                          <C>             <C>              <C>
Balance, beginning of year                   $202,944        $130,489         $141,171
Sales, net of production expenses             (33,824)        (30,014)         (29,222)
Net change in sales and transfer              
   prices, net of production expenses          26,968          29,840          (74,123) 
Changes in estimated future                    
 development costs                             (3,228)         (9,477)          (3,188) 
Extensions, discoveries and improved           
 recovery, net of costs                        59,050          14,928           14,305 
Previously estimated development               
 costs incurred during the year                 3,136           2,995           23,935 
Purchase of reserves in-place                  64,214          16,919           40,569
Sales of reserves in-place                    (11,381)           (426)          (1,139)
Revision of quantity estimates                 24,533          71,188          (20,636)
Accretion of discount                          22,937          13,454           15,536
Net change in income taxes                    (35,512)        (22,377)          10,139
Changes in estimated timing of                
 production and other                         (14,996)        (14,575)          13,142  
                                             --------        --------         --------
Balance, end of year                         $304,841        $202,944         $130,489
                                             ========        ========         ========
</TABLE> 
 
NOTE 16 -- QUARTERLY FINANCIAL DATA (UNAUDITED)
-------------------------------------------------
 
Selected quarterly financial data:
<TABLE> 
<CAPTION> 
                                                                        QUARTER ENDED
                                                   ----------------------------------------------------------
                                                    MARCH 31,     JUNE 30,     SEPTEMBER 30,     DECEMBER 31,
                                                      1995          1995            1995             1995
                                                   ---------      --------     -------------     ------------
                                                              (in thousands, except per share data)
<S>                                                  <C>          <C>            <C>               <C>  
Revenues                                             $93,647      $ 95,256        $103,607         $111,715
Operating profits                                    $ 9,500      $ 10,312        $  9,744         $ 10,953
Net income                                           $   319      $    914        $    483         $    936
Net income per share
   Primary                                           $   .03(1)   $    .06        $    .03         $    .06
   Assuming full dilution                            $   .02      $    .06        $    .03         $    .06
</TABLE> 

<TABLE> 
                                                                        QUARTER ENDED
                                                   ---------------------------------------------------------
                                                   MARCH 31,      JUNE 30,     SEPTEMBER 30,     DECEMBER 31,
                                                      1994          1994           1994             1994
                                                   ---------      --------     -------------     ------------
                                                            (in thousands, except per share data)
<S>                                                  <C>          <C>             <C>              <C>  
Revenues                                             $50,584      $ 67,198        $ 66,224         $ 72,690
Operating profits                                    $ 7,741      $  9,947        $  9,066         $  9,673
Net income (loss)                                    $(1,178)     $    750        $    209         $    790
Net income (loss) per share
   Primary                                           $  (.10)     $    .06        $    .02(2)      $    .07(2)
   Assuming full dilution                            $  (.10)     $    .06        $    .01(2)      $    .05(2)
</TABLE>
-------------------------

(1)  Earnings per share for the quarter ended March 31,1995, has been restated
     to reflect the satisfaction of accrued dividends on the Series C Preferred
     Stock through the conversion of such series into Common Stock on May 25,
     1995 (see Note 6).
(2)  Earnings per share for the quarters ended September 30, 1994, and December
     31, 1994, have been restated to eliminate accrued dividends on the Series C
     Preferred Stock of $433,000 and $504,000 for the respective quarters.  Such
     dividends were paid in additional shares of such stock on January 2, 1995
     (See Note 5).

                                      F-22