<PAGE>   1

                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549

                                    FORM 10-K

                                   (Mark One)

  [X]          ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 2000
                                       OR
  [ ]        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

               For the transition period from _______to ________.

                         Commission file number 0-22576

                                COHO ENERGY, INC.
             (Exact name of registrant as specified in its charter)

            Texas                                                75-2488635
-------------------------------                           ----------------------
(State or other jurisdiction of                               (IRS Employer
incorporation or organization)                            Identification Number)

     14785 Preston Road, Suite 860
              Dallas, Texas                                 75240
----------------------------------------                  ----------
(Address of principal executive offices)                  (Zip Code)

               Registrant's telephone number, including area code:
                                 (972) 774-8300
                                 --------------

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

           Securities registered pursuant to Section 12(g) of the Act:
                     Common Stock, par value $0.01 per share

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 twelve months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X    No
   ---     ---

Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Section 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court. Yes X    No
                         ---     ---

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. [ ]

As of March 23, 2001, 18,714,175 shares of the registrant's Common Stock were
outstanding and the aggregate market value of all voting stock held by
non-affiliates was $10.7 million based upon the closing price on Nasdaq's OTC
Bulletin Board on such date. The officers and directors of the registrant are
considered affiliates for purposes of this calculation.

INCORPORATION OF DOCUMENTS BY REFERENCE
Portions of Coho Energy, Inc.'s definitive proxy statement relating to the
registrant's 2001 annual meeting of shareholders, which proxy statement will be
filed under the Securities Exchange Act of 1934 within 120 days of the end of
the registrant's fiscal year ended December 31, 2000, are incorporated by
reference into Part III of this Form 10-K.



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                                TABLE OF CONTENTS


<TABLE>
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                                                                                                             PAGE
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<S>                                                                                                           <C>
         PART I

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

         PART II

         Item 5.   Market for Registrant's Common Equity and Related Stockholder Matters......................24
         Item 6.   Selected Financial Data....................................................................25
         Item 7.   Management's Discussion and Analysis of Financial Condition and
                   Results of Operations......................................................................26
         Item 7A.  Quantitative and Qualitative Disclosure about Market Risk..................................39
         Item 8.   Consolidated Financial Statements..........................................................41
         Item 9.   Changes in and Disagreements with Accountants on Accounting and
                   Financial Disclosure.......................................................................65

         PART III

         Item 10.  Directors and Executive Officers of the Registrant.........................................66
         Item 11.  Executive Compensation.....................................................................66
         Item 12.  Security Ownership of Certain Beneficial Owners and Management.............................66
         Item 13.  Certain Relationships and Related Transactions.............................................66

         PART IV

         Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K............................67
</TABLE>






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                           FORWARD-LOOKING STATEMENTS


     This Form 10-K includes statements that may be deemed to be
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All
statements, other than statements of historical facts, included in this Form
10-K that address activities, events or developments that we expect, project,
believe or anticipate will or may occur in the future, including:

     o    crude oil and natural gas reserves;

     o    future acquisitions;

     o    future drilling and operations;

     o    future capital expenditures;

     o    future production costs;

     o    future production of crude oil and natural gas;

     o    future economic performance; and

     o    future net cash flow of proved oil and natural gas reserves

are forward-looking statements. These forward-looking statements are generally
accompanied by words such as "intend," "anticipate," "believe," "estimate,"
"expect," "should" or similar expressions. These statements are based on
assumptions and analyses made by us in light of our experience and our
perception of historical trends, current conditions, expected future
developments and other factors we believe are appropriate in the circumstances.
Important factors that could cause actual results to differ materially from our
estimates or projections include, among others, the following:

     o    the highly competitive nature of the oil and gas exploration and
          production business;

     o    the timing and success of our exploration and development drilling
          programs, which would affect production levels and reserves;

     o    changes to our estimates of oil and gas reserves;

     o    the risk that our earnings may be adversely affected by fluctuating
          energy prices;

     o    the business opportunities, or lack thereof, that may be presented to
          and pursued by us;

     o    risks incident to the drilling and operation of oil and gas wells,
          including environmental liabilities;

     o    the substantial amount of our long-term indebtedness; and

     o    other factors, many of which are beyond our control.

     These types of statements are not guarantees of future performance and
actual results or developments may differ materially from those projected in the
forward-looking statements. You should not rely on this information as an
estimate or prediction of future performance.

DEFINITIONS

     See Page 8 for a list of definitions of certain industry terms used
throughout this document.



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                                     PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

GENERAL

     Coho Energy, Inc. is an independent energy company engaged, through its
wholly owned subsidiaries, in the development and production of, and exploration
for, crude oil and natural gas. Our crude oil activities are concentrated
principally in Mississippi and Oklahoma. At December 31, 2000, our total proved
reserves were 100.8 MMBOE with a net present value of proved reserves discounted
at 10% of $756.6 million, approximately 69% of which were proved developed
reserves, based on year end market prices of $26.80 per barrel for crude oil and
$9.78 per MMbtu for natural gas. Market prices for crude oil and natural gas
have fluctuated significantly over the last three years. These year end market
prices are high in comparison to historical average crude oil and natural gas
prices in the most recent three-year period. Approximately 95% of our total
proved reserves were comprised of crude oil. At December 31, 2000, our
operations were conducted in 19 major producing fields, 16 of which we operated.
Our average working interest in the fields we operate was approximately 80%.

     We were incorporated in June 1993 under the laws of the State of Texas and
conduct a majority of our operations through our subsidiary Coho Resources, Inc.
References in this Form 10-K to "Coho," "we," "our," or "us", except as
otherwise indicated, refer to Coho Energy, Inc. and our subsidiaries. Our
principal executive office is located at 14785 Preston Road, Suite 860, Dallas,
Texas 75240, and our telephone number is (972) 774-8300.

OUR HISTORY

     Mississippi. We commenced operations in Mississippi in the early 1980s and
have focused most of our development efforts in that area. The salt basin in
central Mississippi offered significant long-term potential due to the basin's
large number of mature fields with multiple oil and gas producing sands. The
application of proven technology to these underexploited and underexplored
fields yielded attractive, lower-risk exploitation and exploration
opportunities. As a result of the attractive geology and our experience in
exploiting fields in the area, we have accumulated an inventory of potential
development drilling, secondary recovery and exploration projects in this basin.

     Oklahoma. One of our business strategies has been to acquire additional
properties with geologically complex environments and features similar to our
Mississippi properties and to fully exploit the acquired properties using our
substantial knowledge base and geological expertise gained from our historical
success in Mississippi. In December 1997, we acquired properties from Amoco
Production Company that we believed presented the exploitation opportunity we
were seeking.

     The properties we acquired from Amoco Production Company had approximately
55 MMBOE total proved reserves and represented interests in more than 40,000
gross acres, concentrated primarily in southern Oklahoma, including 12 principal
producing fields. We paid $260.9 million in cash and stock warrants to acquire
these properties.

     Reorganization. On August 23, 1999, we and our wholly-owned subsidiaries,
Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho
Louisiana Production Company and Interstate Natural Gas Company, filed a
voluntary petition for relief under Chapter 11 of the U. S. Bankruptcy Code. We
then filed a plan of reorganization that was confirmed by the bankruptcy court
on March 20, 2000. On March 31, 2000, the plan of reorganization was consummated
and we emerged from bankruptcy.

     The plan of reorganization included the following transactions to complete
the restructuring of our indebtedness:

     o    The borrowing of $183.0 million under our new revolving credit
          facility with a new bank group.

     o    The borrowing of $72.0 million under subordinated notes referred to as
          the standby loan, maturing March 2007. We also issued 2,694,841 shares
          of new common stock, representing 14.4% of our new common stock, as
          debt issuance costs to the lenders under these notes.



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     o    The repayment of borrowings and interest due under the old bank credit
          facility.

     o    Conversion of the old bonds into 15,362,107 shares of new common
          stock, representing 82% of our new common stock.

     As a result of the reorganization, our former principal bondholders and
their affiliates own approximately 88% of our new common stock and own $65.5
million of the outstanding notes issued under our $72 million standby loan.
Please read "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Liquidity and Capital Resources - Credit Facilities"
for a description of the terms of the standby loan.

BUSINESS STRATEGY

     Our strategy is to increase the value of our proved reserves, thereby
increasing shareholder value, by:

     o    focusing on relatively low-risk development activities, such as
          development and delineation drilling, multi-zone recompletions,
          enhancement and/or expansion of existing secondary recovery projects
          that we expect to generate increases in production and cash flow from
          operations;

     o    using these low-risk activities to increase our proved developed
          producing reserves by developing our proved undeveloped reserves;

     o    increasing total proved reserves through the initiation of new
          secondary recovery projects in our existing fields and through the use
          of 2-D and 3-D seismic and other technologies to identify exploration
          projects which we expect will generate new reserves if our exploration
          efforts are successful; and

     o    improving our production performance by installing specialized
          equipment, performing preventative equipment maintenance and
          conducting more extensive well repairs to wells that have failed in
          order to gain added run time in the future and as a result to achieve
          lower operating costs and less downtime for well repairs in the
          future.

In connection with our reorganization in bankruptcy and related operational
restructuring effective March 31, 2000, a new management team and a new board of
directors were selected by our former principal bondholders to lead us as we
emerged from bankruptcy. In addition to developing our business strategy, the
new management team has:

     o    developed a detailed operating plan through December 2001 to implement
          our business strategy with a continuing development plan into 2002;

     o    assembled the personnel required to execute our operating plan and
          eliminated unnecessary positions; and

     o    began implementing this operating plan.

During the first 90 days following our emergence from bankruptcy, our management
team substantially completed the development of our operating plan, including
detailed business plans for each of our major fields, and the selection of
personnel. We commenced implementing the capital expenditure projects identified
in the operating plan in late June 2000.

     2000 Capital Expenditures. During 2000, we incurred capital expenditures of
$25.3 million. We directed our initial capital expenditures to capital projects
that were expected to generate the largest ultimate increase in production and
cash flow from operations. We expended approximately 60% of our initial capital
expenditures on projects in our Mississippi fields and we spent the remaining
40% on projects in our Oklahoma fields. Approximately 70% of these capital
expenditures was spent on recompletions, workovers and waterflood projects on
existing wells to enhance production. Our expenditures for the drilling of new
wells were modest during 2000 because drilling did not begin under our new
operating plan until late in the second quarter of 2000 and rig availability was
limited during the third and fourth quarters. During 2000, we drilled three
wells in Mississippi, 19 wells in Oklahoma and participated in the drilling of
one outside operated well in Oklahoma, including:

     o    one deepening drilled in the first quarter;



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     o    three wells drilled in the second quarter;

     o    nine wells drilled in the third quarter; and

     o    ten wells drilled in the fourth quarter.

Of these 23 wells, nineteen were completed as producing wells, three gas wells
and 16 oil wells. Three of the other four wells were dry holes, two low cost gas
wells in Oklahoma and one exploratory oil well in Mississippi, and the remaining
well was completed as a water injection well. We also had two wells drilling in
Mississippi and three wells drilling in Oklahoma at year end.

     2001 Capital Expenditures. We have budgeted $40.2 million for capital
expenditures during 2001, of which approximately 70% is planned for projects in
the first half of the year. We have drilled or plan to drill 12 wells in the
first quarter of 2001 in addition to the five wells that were drilling at year
end. The emphasis of our 2001 capital expenditure program is on:

     o    the development of our East Velma Middle Block waterflood project;

     o    infill drilling and waterflood projects in our East Fitts and Tatums
          fields;

     o    continued development of our pilot waterflood projects that were
          started in 2000 in the Graham Deese, North Alma Deese and Jennings
          Deese units; and

     o    further development drilling in several of our Mississippi fields,
          including the Brookhaven, Laurel, Martinville and Soso fields.

These projects are discussed more fully under "Oil and Gas Operations."

     Operating Plan. We have a high level of indebtedness after the
reorganization. Our total consolidated indebtedness as of December 31, 2000 was
$282.4 million and the ratio of total consolidated indebtedness to total
capitalization was 82%. Due to our high level of indebtedness, our operating
plan during 2000 and 2001 focuses on capital projects that should generate
increases in:

     o    production;

     o    cash flow from operations; and

     o    proved developed producing crude oil and natural gas reserves and, to
          a lesser extent, total proved reserves.

     The majority of our capital expenditures during 2000 and 2001 are allocated
to projects that are classified as proved undeveloped and proved non-producing
projects in our reserve report. Our field development projects include the
following activities to maximize production and increase proved developed
producing reserves:

     o    recompletions;

     o    enhancement of production facilities;

     o    installment of new waterflood projects;

     o    expansion of existing waterflood injection projects;

     o    installment of pump off controllers to improve lift efficiency;

     o    multi-zone completions; and

     o    development/delineation drilling.




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     Although total reserves may not increase substantially as a result of this
work, the value of proved developed producing reserves and cash flow from
operations should increase if these projects are successful, thereby increasing
the value of our reserves in the banks' valuation analysis in determining our
borrowing capacity and also increasing shareholder value.

     Our 2001 operating plan includes some exploration prospects in the vicinity
of our existing fields using technologies that include 3-D seismic technology.
3-D seismic technology is a tool that allows us to look at vertical
cross-sections as well as horizontal cross-sections beneath the prospective area
of our properties on a very small grid pattern. We first began using 3-D seismic
technology in the Laurel field in Mississippi in 1983, and have shot two large
3-D seismic programs in and around our existing properties in Mississippi within
the last five years. At the time of purchase, we acquired four 3-D seismic
programs in and around our Oklahoma properties. These programs have produced an
attractive inventory of exploration projects that will increase total reserves
if these projects are successful.

     Recapitalization. As previously described above, we are highly leveraged
with a ratio of total consolidated indebtedness to total capitalization of 82%.
Although we believe we currently have adequate sources of liquidity for the
budgeted activities that we expect to conduct in 2001, this high level of
indebtedness has several important effects on our future operations, including:

     o    requiring us to devote a substantial portion of our cash flow from
          operations to pay interest on our indebtedness and not for other uses,
          such as funding working capital or capital expenditures;

     o    limiting our ability to obtain additional financing in the future for
          working capital, capital expenditures, acquisitions, general corporate
          purposes or other purposes thereby restricting our future growth;

     o    putting us at a competitive disadvantage to our competitors who have
          less debt than us; and

     o    limiting our flexibility to plan for, or to react to, changes in our
          business and the oil and gas industry.

We are exploring alternatives to reduce our leverage ratio. Our alternatives
include, but are not limited to:

     o    entering into an equity transaction with another company with a lower
          leverage ratio;

     o    raising additional equity to repay all or a substantial portion of our
          indebtedness outstanding under the standby loan;

     o    converting all or a substantial portion of the standby loan to equity;
          or

     o    combining one or more of these various alternatives.

     Discontinuation of Tunisian Operations. We have decided to discontinue our
participation in the exploration of two Tunisia, North Africa permits due to
required capital commitments during 2001 exceeding $7 million net to our
interest. Our two subsidiaries that own these permits, Coho Anaguid, Inc. and
Coho International Limited, filed for protection under Chapter 11 of the United
States Bankruptcy Code on February 20, 2001 to preserve our ownership in these
permits under the protection of the bankruptcy court while we attempt to
negotiate sales of our interests in the permits to a third party or parties and
to reach settlements with respect to our obligations under the permits. See "Oil
and Gas Operations" for further discussion.




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DEFINITIONS

     Unless otherwise indicated, natural gas volumes are stated at the legal
pressure base of the State or area in which the reserves are located at 60
degrees Fahrenheit. The following definitions apply to the technical terms used
in this Form 10-K:

     "2-D seismic" means an interpretive data set that allows a view of a
vertical cross-section beneath a prospective area.

     "3-D seismic" means an interpretive data set that allows a view of a
vertical cross-section as well as a horizontal cross-section beneath a
prospective area.

     "Bbls" means barrels of crude oil, condensate or natural gas liquids, and
is equivalent to 42 U.S. gallons.

     "Bcf" means billions of cubic feet.

     "BOE" means barrel of oil equivalent, assuming a ratio of six Mcf to one
Bbl.

     "BOPD" means Bbls per day.

     "Developed acreage" means acreage which consists of acres spaced or
assignable to productive wells.

     "Dry hole" means a well found to be incapable of producing either crude oil
or natural gas in sufficient quantities to justify completion as a crude oil or
natural gas well.

     "Gravity" means the Standard American Petroleum Institute method for
specifying the density of crude petroleum.

     "Gross" means the number of wells or acres in which we have an interest.

     "MBbls" means thousands of Bbls.

     "MBOE" means thousands of BOE.

     "Mcf" means thousands of cubic feet.

     "MMBbls" means millions of Bbls.

     "MMBOE" means millions of BOE.

     "MMbtu" means millions of British Thermal Units.

     "MMcf" means millions of cubic feet.

     "Net" is determined by multiplying gross wells or acres by our working
interest in such wells or acres.

     "Present value of proved reserves" means the present value discounted at
10% of estimated future net cash flows before income taxes of proved crude oil
and natural gas reserves.

     "Productive well" means a well that is not a dry hole.

     "Proved developed reserves" means only those proved reserves expected to be
recovered from existing completion intervals in existing wells and those proved
reserves that exist behind the casing of existing wells when the cost of making
those proved reserves available for production is relatively small relative to
the cost of a new well.

     "Proved reserves" means natural gas, crude oil, condensate and natural gas
liquids on a net revenue interest basis, found to be commercially recoverable.

     "Proved undeveloped reserves" means those reserves expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion.




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     "Recompletion" means leaving one formation for another formation within a
well bore.

     "Secondary recovery" means a method of oil and natural gas extraction in
which energy sources extrinsic to the reservoir are used.

     "Undeveloped acreage" means leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of crude oil and natural gas, regardless of whether or not that
acreage contains proved reserves.

     "Unitized" means the royalty and working interests are pooled within a
given geological and/or geographical area.

     "Waterflood" means the injection of water into oil bearing formations to
displace the oil.

     "Workover" means the performing of work within a well bore associated with
the currently producing formation.


OIL AND GAS OPERATIONS

     General. In the conduct of our operations, we apply the latest developments
in technology, completion and production techniques, and we employ new
innovations in equipment to enhance exploitation, secondary recovery and
exploration activities on oil and gas properties. The detailed application of
these areas of our expertise to older properties has played an important role in
our continuing production and reserve development. In 2000, we have conducted
our operations mainly on the following fields:

     o    Mississippi - Brookhaven, Martinville and Soso

     o    Oklahoma - Tatums, East Fitts, East Velma Middle Block, Eola, North
          Alma Deese and Graham Deese

     Our capital expenditures totaled $6.3 million in 1999 and $25.3 million in
2000. We kept our 1999 capital expenditures very low due to budget constraints
resulting from the substantial decline in crude oil prices in 1998 and early
1999, as well as expenditure constraints imposed by the bankruptcy court
subsequent to August 23, 1999. In mid-year 2000, we resumed our development
drilling program and drilled a total of 22 gross or 14.8 net development wells
with a success rate of 90%. Initial combined net production rates from our
development drilling totaled 626 net BOE per day. This development drilling also
resulted in the reclassification of reserves from proved undeveloped reserves to
proved developed producing reserves. Well repair and recompletion activity in
2000 enabled us to complete in excess of 200 workover and repair operations and
95 recompletions. We plan to continue this activity in 2001, and efforts are
being concentrated to steadily make more extensive repairs to wells that have
failed in order to gain added run time and ultimately reduce operating costs.

     Exploitation. Our properties are generally characterized as being mature
and having multiple layers of oil and gas reservoirs, which are broken into
numerous separate sources of supply due to the complex geology in many of the
fields in which we operate. Our properties have a large number of wells that
either we or other operators have drilled over the past 50 years. The data from
this number of wells assists us in developing detailed geologic interpretations
of our active regions, which continue to improve our understanding of the
numerous hydrocarbon deposits on these properties.

     The changing economics of the value of these multiple reservoirs coupled
with the ability to deploy capital and improved technology to identify and
develop these sources of supply, presents us with new opportunities to produce
reserves that were previously unattractive, unrecognized as productive or found
to be isolated from the existing producing wells on a property. One of the key
elements in our strategy of building reserves and creating shareholder value has
been to concentrate on the full development of mature fields, which exhibit the
potential for having been either underdeveloped or having further exploration
opportunities through the utilization of new or existing technology.

     Secondary Recovery. The mature nature of our producing properties has
provided us with opportunities to employ secondary recovery techniques to
increase the recovery of reserves in place that have not been recovered by
primary production means. In the majority of situations, the existing wells are
utilized for this purpose, which greatly reduces the capital outlays otherwise
necessary to connect to these sources of production. In addition, the water
produced from these operations is re-injected into the reservoir creating a
so-called water-drive mechanism to





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extract the oil which was not produced under primary means. These projects have
historically demonstrated strong production response and meaningful reserve
additions.

     We have identified 20 potential secondary projects in Mississippi. We have
successfully developed six of these projects and are in the process of
installing one additional new secondary project at this time. The acquisition of
the Oklahoma properties in 1997 presented us with nine existing secondary
projects and we have identified 11 additional potential secondary projects on
these properties. We have commenced a secondary project on the East Velma Middle
Block Unit, which has been successfully performed by other operators on both
sides of our property. Completion of the first phase of the installation is
scheduled in the first half of 2001.

     We are continuing to improve recoveries on existing secondary projects by
carefully monitoring the waterflood response to improve the sweep efficiency on
these projects. As an example, we have launched pilot waterflood projects within
our existing active waterflood projects in the Brookhaven field, Graham Deese
Unit, North Alma Deese Unit, Jennings Deese Unit and Tatums Unit. Our infield
development program is in association with the pilot waterflood project on the
Tatums Unit. We plan to continue such pilot projects until we see sufficient
encouragement to expand the pilot waterflood projects to the other parts of the
field where indications are that the results will be attractive.

     Exploration. The complex geology of many of our oil and gas properties
provides us with the opportunity to drill for new sources of supply within the
area of our existing properties and to utilize the existing well control to
substantially reduce dry hole risk. In order to further define our targets and
assist in the geologic interpretation of these complex features, we have
completed two 3-D seismic surveys in Mississippi, and are in the process of
evaluating approximately 95 square miles of 3-D seismic data and 2,750 miles of
2-D seismic data acquired along with the Oklahoma properties. 2-D seismic data
is a tool that allows us to look at vertical cross-sections beneath the
prospective area of our properties typically on a much wider grid pattern. A 3-D
seismic survey is a computer enhanced seismic survey that allows us to look at
subsurface structures in an area in a three dimensional view and provides much
greater detail and resolution of the geologic picture than using 2-D seismic
data alone. This seismic data as well as our geologic interpretations has
provided us with several prospective drilling opportunities, which are being
further evaluated.

     In 2000, we drilled an exploratory step-out well on an untested fault block
in the Brookhaven field, which was unsuccessful in finding the anticipated
hydrocarbon trap projected based on 2-D seismic interpretation. Currently, we
are conducting exploratory work on several seismic structures near existing
production in Oklahoma and are negotiating the drilling rights on a number of
prospects adjacent or on trend with our current properties. In the Mississippi
properties, we are employing a combination of 2-D and 3-D seismic data to make
detailed geologic interpretations of our existing properties on which we plan to
continue to conduct in-field development drilling, and to assist in enhancing
the installation and operation of secondary projects.

PRINCIPAL AREAS OF ACTIVITY

     The following table sets forth, for our major producing areas, average net
daily production of crude oil and natural gas on a BOE basis for each of the
years in the three-year period ended December 31, 2000, and the number of
productive wells producing at December 31, 2000. We sold our Louisiana
properties on December 2, 1998.

<TABLE>
<CAPTION>
                   Year Ended December 31 (a)                                      At December 31, 2000
               --------------------------------                                    --------------------
                 1998        1999        2000
               --------    --------    --------
                                                                  Productive Wells
                                                   --------------------------------------------   Percentage
                                                        Gross Wells             Net Wells           of Net       Average
                                                   --------------------    --------------------     Wells        Working
                BOE/Day    BOE/Day     BOE/Day       Oil         Gas         Oil         Gas       Operated     Interest
               --------    --------    --------    --------    --------    --------    --------    --------     --------

<S>            <C>         <C>         <C>         <C>         <C>         <C>         <C>         <C>          <C>
Mississippi       8,202       4,621       4,725         137           3         126           3          99%          95%
Oklahoma          6,345       5,414       5,598       1,374         120         510          51          93%          41%
Louisiana         2,452          --          --          --          --          --          --          --           --
Other               600         315         285          34          --          15          --          19%          49%
               --------    --------    --------    --------    --------    --------    --------

     Total       17,599      10,350      10,608       1,545         123         651          54
               ========    ========    ========    ========    ========    ========    ========
</TABLE>


(a) In response to depressed crude oil prices during 1998 and early 1999, we
significantly reduced minor and major repairs and drilling activity on our
operated properties beginning in August 1998, ceased all repair work and






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drilling activity in December 1998 and halted production on wells we determined
to be uneconomical. We restarted repairs and maintenance on the properties we
operate and began doing limited recompletion and workover activity in the second
half of 1999. After we emerged from bankruptcy in April 2000, we initiated a
capital expenditure program that commenced in June 2000 to return all remaining
shut-in wells to production and to begin drilling and recompletion projects to
increase production.

MID-CONTINENT AREA

     In December 1997, we acquired interests in approximately 40,000 gross acres
concentrated primarily in southern Oklahoma, including 12 principal producing
fields. Of the 12 principal producing fields, we are the operator of ten fields.
At December 31, 2000 we had an average working interest of approximately 75% in
the ten fields we operate.

     These properties are very similar to our Mississippi salt basin operations
because these properties will respond to very detailed study and exploitation to
recover additional reserves not yet developed. In 2000, a total of 19 wells were
drilled on the operated properties and one well was drilled on an outside
operated property. A total of 17 gross wells were successfully completed as
producing wells in 2000, including the outside operated well, and one well was
completed as a water injection well. One dry hole was drilled in the Graham
Deese field in an attempt to develop shallow gas deposits at approximately 1,600
feet. One of our 17 successfully completed wells was a shallow gas well drilled
in the Graham Deese area with an initial flow rate of 180 Mcf per day. We own a
100% working interest in this well. The majority of the other drilling on our
operated properties was directed at in-field development of proved undeveloped
reserves primarily in the Tatums Unit, where we have a 49% working interest. In
addition during 2000, we began interpreting 3-D seismic information, which had
been acquired with the purchase of the Oklahoma properties, and have identified
several drilling opportunities that we plan to commence early in 2001.

     Bumpass Field, Oklahoma. The Bumpass field, located in Carter County,
Oklahoma, was discovered in 1924. Production is primarily from both structural
and stratigraphic traps within the Deese and Springer reservoirs. The Deese
reservoirs are typically encountered at depths between 3,500 and 4,500 feet with
the Springer reservoirs located from 4,500 to 6,700 feet. We own an average
working interest of approximately 64% in the Bumpass field.

     In 2000, our primary focus at Bumpass was to improve the operation of the
existing Deese waterflood project by returning wells to production, which had
not been repaired due to capital constraints in the prior year. In addition,
based on detailed geologic interpretation of the field, it was found that
several Springer completions drilled in 1998 and 1999 could be enhanced by
implementing waterflood operations. In 2000, we initiated one new waterflood to
recover additional reserves from these segmented reservoirs and currently plan
to implement two additional waterflood projects for this purpose during 2001.

     Average net daily production in 2000 was 435 BOE compared to 451 BOE per
day in 1999. Net proved reserves at December 31, 2000 totaled 4.0 MMBOE, a
decrease of 11% from 4.5 MMBOE at the end of 1999. The decrease in reserves is
primarily due to reserves produced during 2000 coupled with downward revisions
in reserve estimates related to actual reservoir performance during 2000 in the
Springer gas and Deese waterflood formations.

     East Fitts Field, Oklahoma. The East Fitts field was discovered in 1933 and
is located in Pontotoc County, Oklahoma near the city of Ada. Production in the
field is primarily from the Cromwell, Hunton and Viola reservoirs ranging in
depth from 2,400 feet to 5,000 feet. Our average working interest in the East
Fitts field is approximately 82%.

     In late 2000, we found shallow gas potential at a depth of approximately
1,600 feet in this mature field and have initiated plans to begin testing this
potential using idle or available existing wellbores in the unit. We plan to
continue to recomplete idle wells to exploit this shallow gas potential since
current product prices are attractive.

     Our current emphasis at East Fitts, in addition to our plan to pursue the
shallow gas, is to undertake the infill drilling of the Viola reservoir. We
believe this development drilling will not only increase existing production but
will also allow us to reclassify proved undeveloped reserves to proved developed
producing reserves. In 2000, we drilled the EFU #12-6 as part of a pilot program
to more fully evaluate this concept. The EFU # 12-6 was completed with an
initial gross production rate of 90 BOE per day, and was continuing to produce
at this rate by the end of 2000. This well has been encouraging and has prompted
us to plan additional drilling for the East Fitts unit in 2001. At year end
2000, we were waiting on an available drilling rig to begin drilling in the East
Fitts unit.




                                       11
<PAGE>   12



     Average net daily production in 2000 was 1,182 BOE as compared to an
average net daily production in 1999 of 997 BOE, a 19% increase. Net proved
reserves at December 31, 2000 totaled 23.1 MMBOE representing approximately 23%
of our total proved reserves. Year end 2000 net proved reserves are down from
the net proved reserves at December 31, 1999, which totaled 23.7 MMBOE. The
change in reserves is primarily due to reserves produced during 2000 and
downward revisions in reserve estimates related to increased operating costs
based on actual costs incurred during 2000.

     East Velma Middle Block Field, Oklahoma. The East Velma Middle Block is
located in Stephens County, Oklahoma and was discovered in 1949. The field has
been a primary producer in the Sims and Humphreys formations. The field is
characterized as a steeply dipping structure with a large trapping fault. Our
average working interest in this field is 63%.

     In 2000, we initiated plans to waterflood both of the producing formations
based on offset performance in other segments of the field, which are outside
operated. East Velma Middle Block is the only remaining block along this
structural complex, which has not been enhanced through secondary recovery
efforts. The majority of the work during 2000 has been to utilize existing
wellbores for conversion to water injection wells. In 2000, we started the
initial water injection in two wells and have seen early response in one of the
offset producers within a two-month period. These encouraging results have led
us to accelerate the planned installation of the waterflood facilities. This
program was ongoing as of year end 2000 and is continuing into 2001.

     Proved net reserves totaled 11.6 MMBOE as of December 31, 2000,
representing approximately 12% of our total proved reserves, as compared to
proved net reserves of 11.8 MMBOE at year end 1999. Daily average net production
from the East Middle Block field in 2000 averaged 516 BOE down from the 607 BOE
per day experienced in 1999. Production from this field in 2000 was not
significantly affected by the initiation of the waterflood activity due to the
recent time frame in which this activity was started.

     Sholem Alechem Fault Block "A" Field, Oklahoma. The Sholem Alechem Fault
Block "A" field is located in Stephens County, Oklahoma and was discovered in
1947. As with the Bumpass field, the production at Sholem Alechem originates
primarily from the Deese and Springer reservoirs. We own an average working
interest in the field of approximately 87%.

     In 2000, the main focus of work in Sholem Alechem was the continued repair
of wells which had been left down due to capital constraints in 1999, and to
increase the operating efficiency of the unit. We also deepened the Taylor #6
well to test the Goodwin section of the Basal Springer sand. We successfully
completed this gas well with an initial gross flow rate of 640 Mcf per day (278
Mcf per day net). In addition, we continued to look for inactive well bores that
could be deepened to test the Goodwin and Flattop sections of the Springer
formation where several successful deepenings were done in 1998 and 1999. The
scarcity of suitable or available wellbores for this purpose has resulted in our
attempting to trade or purchase wellbores from other operators in the area to
use to perform recompletions. In 2000, we were successful in arranging to trade
for three wellbores, which we plan to utilize to exploit deeper gas reserve
potential in 2001.

     Net daily production in 2000 from the Sholem Alechem field was 728 BOE,
representing a 3% increase from the 705 BOE average in 1999. Net proved reserves
at December 31, 2000 totaled 6.6 MMBOE, representing a decline of 6% from year
end 1999 primarily due to reserves produced during 2000 and downward revisions
in reserve estimates related to increased operating costs based on actual costs
incurred during 2000.

     Tatums Field, Oklahoma. The Tatums field is located in Carter County,
Oklahoma and was discovered in 1927. The field is primarily a Deese sand
structure between the average depths of 2,500 and 3000 feet. Our average working
interest in the Tatums field is 49%.

     During 2000, we reprocessed our 3-D seismic in the Tatums field, and were
able to discern that the field was made up of a number of flow channels
primarily on the west side of the field, which had not been previously
recognized. We began an in-field development drilling program as a pilot project
to further develop the reserves believed to lie in these areas, in a portion of
the field that was not as densely developed as the east and southeast portions.
As of December 31, 2000, we had drilled a total of eleven wells and were
encouraged with the amount of undrained pay sands that were encountered. We now
plan to augment the existing waterflood program to increase water injection into
these areas to enhance the recovery of these remaining reserves.

     Net daily production from the Tatums field in 2000 averaged 597 BOE per
day, representing an increase of 12%, as compared to average net daily
production of 534 BOE in 1999. The net daily production figures for 2000 do not
reflect any benefit from the planned increased water injection into this new
pilot area. Total net proved reserves as of December





                                       12
<PAGE>   13

31, 2000 were 3.5 MMBOE, an increase of 7% from the total net proved reserves as
of December 31, 1999 of 3.3 MMBOE, due to the development drilling program.

     Other Oklahoma. We operate five other fields in Oklahoma:

     o    Cox Penn;

     o    Eola;

     o    Graham Deese;

     o    Jennings Deese; and

     o    North Alma Deese

As discussed under "Secondary Recovery", we launched pilot waterflood projects
in the North Alma Deese, Jennings Deese and Graham Deese units during 2000.
Continued development of these waterflood projects is included in our 2001
capital expenditure program.

     Total average net daily production in 2000 from these fields was 1,167 BOE
as compared to average net daily production of 1,028 BOE in 1999. At December
31, 2000, net proved reserves in these fields were approximately 17.4 MMBOE. Net
proved reserves in these fields were 18.5 MMBOE at December 31, 1999.

     We also have working interests in three other producing properties in
Oklahoma operated by others. At December 31, 2000, net proved reserves in these
three fields were estimated at 2.7 MMBOE as compared to net reserves of 3.9
MMBOE at December 31, 1999. Net average daily production from these properties
was 973 BOE in 2000 as compared to average net daily production of 1,041 BOE in
1999.

GULF COAST AREA

     Brookhaven Field, Mississippi. The Brookhaven field is located in Lincoln
County, Mississippi near the town of Brookhaven. The field was discovered in
1943 and covers a surface area of approximately 13,000 acres. We acquired the
Brookhaven field in 1995 and currently own an average working interest of 98% in
the field. The field has had approximately 200 wells drilled on the structure to
various depths. Productive intervals in the field range from the Tuscaloosa
formation at approximately 10,500 feet to the Hosston formation at 16,700 feet.
The Tuscaloosa formation was the primary reservoir that was developed in the
field, until we added the Washita Fredicksburg, Paluxy and Rodessa formations
through deeper exploratory drilling.

     In 2000, we drilled two wells to further develop and extend the productive
limits of the Washita Fredicksburg and Paluxy formations using reprocessed
seismic data. As mentioned previously, one of the wells was an unsuccessful
exploratory well that was drilled to test an untested fault block on the east
flank of the field. The second well was a successful development well in the
Washita Fredicksburg formation with a pumping rate of 288 BOE gross per day or
205 BOE net at completion. At the end of 2000, we were in the process of
installing a new secondary recovery project on the west side of the field to
recover remaining reserves from a Tuscaloosa reservoir, which has not been
waterflooded. This project is ongoing and is expected to be completed in the
first quarter of 2001, when water injection will be initiated.

     Production in Brookhaven in 2000, averaged 514 BOE net per day and net
proved reserves at December 31, 2000 were 5.2 MMBOE. Daily production was 8%
lower than 1999 levels due to natural production decline. Reserves were 19%
below 1999 as a result of reserves produced during 2000 in addition to downward
revisions in reserves. Reserves were revised downward due to re-interpretation
of the aerial extent of one of the productive intervals, actual reservoir
performance during 2000 and increased operating costs associated with returning
wells to production in 2000. Additional development drilling and the expansion
of waterflood projects are planned for 2001.

     Laurel Field, Mississippi. The Laurel field is located in Jones County,
Mississippi and lies predominantly within Laurel city limits. We acquired our
initial interest in this field in 1983 and currently own an average working
interest of 95% in the field. The field is a multi-pay geologic setting with
producing horizons from the Eutaw formation at approximately 7,500 feet to the
Hosston formation at approximately 13,500 feet. It is our largest oil producing
property and represents approximately 46% of our total Mississippi production on
a BOE basis in 2000. At December 31, 2000, the






                                       13
<PAGE>   14

field contained 42 gross wells producing from the Stanley, Christmas,
Tuscaloosa, Washita Fredicksburg, Paluxy, Mooringsport, Rodessa, Sligo and
Hosston reservoirs. We employed 3-D seismic technology to assist in defining the
multi-pay zones in the field and performed an extensive drilling program to
increase primary production, using a combination of vertical, high-angle and
horizontal drilling techniques.

     The average net daily production in 2000 from Laurel was 2,210 BOE, down 4%
from 1999 levels. At December 31, 2000, net proved reserves were 9.9 MMBOE, down
approximately 21% from year end 1999. The decrease in reserves is attributable
to reserves produced during 2000 coupled with downward revisions in reserve
estimates. The downward revisions in reserve estimates relate to actual
reservoir performance during 2000, re-mapping of productive limits within
several fault blocks and increased operating costs based on actual costs
incurred during 2000.

     We have identified additional development locations within the Laurel
Field, and plan to initiate some additional development drilling on these
projects in 2001. In addition, we have also mapped several untested fault traps
on the west side of the Laurel field structure, which we are evaluating for
either drilling or negotiating farm-out arrangements, depending on the risk
assessment.

     Martinville Field, Mississippi. The Martinville Field is located in Simpson
County, Mississippi. We acquired our initial interest in the Martinville field
in 1989 and currently own an average working interest of 99% in the field. The
field covers more than 7,400 acres and currently has 19 gross producing wells.
The Martinville field is similar to the Laurel field, in the respect that it is
geologically complex with multiple horizons. The field consists of numerous
producing formations from approximately 8,500 feet in the Washita Fredicksburg
formation to the Cotton Valley formation at approximately 14,500 feet. The field
has identified reserves in the Mooringsport, Rodessa, Sligo and Hosston
formations as well as the Washita Fredicksburg and Cotton Valley formations.

     In 2000, we drilled one development well that was completed as a producing
oil well in July and drilled a second well that was still drilling at year end.
Both of these wells were drilled to further develop the 8,500 feet Washita
Fredicksburg formation. This drilling program was delayed in 2000 due to the
need to re-interpret portions of our 3-D seismic survey and the unavailability
of drilling rigs due to the surge of drilling activity in the industry towards
the end of 2000. We plan to continue this development drilling program in 2001
and to concentrate on improving the monitoring of waterflood response to
maximize secondary recoveries in the field.

     Net proved reserves at year end 2000 totaled 4.0 MMBOE, a 25% decrease from
year end 1999. The decrease in net reserves is primarily due to reserves
produced during 2000, downward revisions in reserve estimates attributable to
actual reservoir performance during 2000 and increased operating costs based on
actual costs incurred during 2000. Production in 2000 averaged a daily net rate
of 647 BOE, which was a 17% decline from production levels in 1999. The primary
decline in average daily net production in 2000 as compared to 1999 was due to
the production declines on the MFU 14-13#1 well from peak production rates of
approximately 500 BOPD in 1999 down to 200 BOPD by the third quarter of 2000.

     Soso Field, Mississippi. The Soso Field is located in Smith and Jones
Counties, Mississippi and covers approximately 6,500 acres. We acquired our
initial interest in this field in 1990 and currently own an average working
interest of 94% in the field.

     Since 1997, we have initiated secondary recovery projects in the Cotton
Valley, Sligo and Rodessa formations. We directed our efforts in 2000 toward
improving the secondary recovery efficiency by increasing water injection rates
and re-activating shut-in wells associated with improving this project. In 2000,
the average daily net production was 486 BOE, an increase of 37% from the 1999
average daily net production of 354 BOE.

     In 1998, we acquired 35 miles of new 2-D seismic data across the Soso
field. This 2-D seismic data has enhanced our interpretation of the geologic
structures of the Soso field and led to the commitment to drill two additional
development wells for the Cotton Valley formation. We began drilling one of
these wells in December 2000 which was completed in February 2001. The second
well was spud in February 2001 and is still drilling.

     Net proved reserves as of December 31, 2000 in the Soso field were 5.1
MMBOE, representing an 8% decrease from net proved reserves at year end 1999,
primarily due to reserves produced during 2000 and downward revisions in reserve
estimates related to increased operating costs based on actual costs incurred
during 2000.

     Summerland Field, Mississippi. The Summerland field is located in Jones and
Covington Counties, Mississippi and covers approximately 1,300 acres. We
acquired operating control of the Summerland field in 1989 and currently own an






                                       14
<PAGE>   15

average working interest of 90%. The productive structure of the field is a
broad, elongated, fault-bounded anticline with productive intervals from the
Tuscaloosa formation at approximately 6,000 feet to the Mooringsport formation
at 12,500 feet. At December 31, 2000, we operated 21 gross producing wells.

     In 2000, we directed our operations primarily to returning wells to
production and improving lift efficiency on the producing wells. In addition,
several projects were completed to assist in the disposal of water produced from
this field, to ease production restrictions caused by produced water in past
operations. Average daily net production for 2000 was 714 BOE, or an increase of
45% over average daily net production of 494 BOE for 1999.

     At December 31, 2000, the Summerland field had proved reserves of 4.0
MMBOE, a decrease of approximately 29% from year end 1999. This decrease was
primarily due to reserves produced during 2000 and downward revisions in reserve
estimates related to increased operating costs based on actual costs incurred
during 2000.

OTHER DOMESTIC PROPERTIES

      We also have working interests in other producing properties in
Mississippi and Texas. We operate the Bentonia and Cranfield fields in
Mississippi. We own non-operated working interests in the Glazier field in
Mississippi, the Clarksville field in Texas and a field in Federal waters
offshore North Padre Island, Texas. As of December 31, 2000, these fields had
combined net proved reserves of 3.6 MMBOE. Aggregate average daily net
production from these properties for both 1999 and 2000 was approximately 430
BOE.

     In addition, we have leasehold and production in approximately 2,700 gross
acres in Navarro County, Texas, which currently produces from the Cotton Valley
formation. In 2001, we intend to explore the Bossier sand development for
potential natural gas production on our acreage in Texas by acquiring farm-outs
to these shallow rights and utilizing our existing wells to test the productive
potential.

TUNISIAN OPERATIONS

     We have decided to discontinue our participation in the exploration of two
Tunisia, North Africa permits due to capital commitments in excess of $7
million, net to our interest, during 2001, including cash calls currently due
totaling $753,000 for January and February on the Anaguid permit. We own a 45.8%
interest in the Anaguid permit operated by Anadarko Tunisia Anaguid Company and
a 12.5% interest in the Fejaj permit operated by Bligh Tunisia, Inc. We have
been seeking buyers for our interests in these two permits since emerging from
bankruptcy in March 2000 but have not yet been successful in selling these
interests. We believe it is in our best interest to preserve our ownership in
these permits under the protection of the bankruptcy court while we attempt to
negotiate sales of our interests in the permits to a third party or parties and
to reach settlements with respect to our obligations under the permits.
Therefore, our two subsidiaries that own these permits, Coho Anaguid, Inc. and
Coho International Limited, filed for protection under Chapter 11 of the United
States Bankruptcy Code on February 20, 2001. We anticipate that the other
interest owners in these Tunisian permits will claim that these two subsidiaries
are obligated for their share of the 2001 capital commitments totaling in excess
of $7 million under the terms of the related operating and permit agreements.

PRODUCTION

         The following table contains information regarding our production
volumes, average prices received and average production costs associated with
our sales of crude oil and natural gas for each of the years in the three-year
period ended December 31, 2000:

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

<S>                                                   <C>          <C>          <C>
CRUDE OIL:
  Volumes (MBbls) ................................        5,069        3,343        3,535
  Average sales price (per Bbl)(a) ...............    $   10.40    $   15.40    $   23.31
NATURAL GAS:
  Volumes (MMcf) (b) .............................        8,124        2,608        2,087
  Average sales price (per Mcf)(c) ...............    $    1.98    $    2.24    $    3.73
AVERAGE PRODUCTION COST (per BOE)(d) .............    $    4.18    $    5.60    $    7.55
</TABLE>





                                       15
<PAGE>   16

(a)  Includes the effects of crude oil price hedging contracts. Price per Bbl
     before the effect of hedging was $10.40 for the year ended December 31,
     1998, $15.40 for the year ended December 31, 1999 and $26.10 for the year
     ended December 31, 2000.

(b)  Natural gas production in 1998 includes production from the Louisiana
     properties that were sold on December 2, 1998.

(c)  Includes the effects of natural gas price hedging contracts. Price per Mcf
     before the effect of hedging was $1.92 for the year ended December 31,
     1998, $2.24 for the year ended December 31, 1999 and $3.99 for the year
     ended December 31, 2000.

(d)  Includes lease operating expenses and production taxes. Average production
     costs per BOE increased from 1999 to 2000 primarily due to increases in
     production taxes, fluid production, utility costs, costs for well services
     and materials. See "Management's Discussion and Analysis-Results of
     Operations" for a more detailed discussion.

DRILLING ACTIVITIES

     During the periods indicated, we drilled or participated in the drilling of
the following wells:

<TABLE>
<CAPTION>
                                                                    Year Ended December 31,
                                                      --------------------------------------------------
                                                           1998              1999              2000
                                                      --------------    --------------    --------------
                                                      Gross     Net     Gross     Net     Gross     Net
                                                      -----    -----    -----    -----    -----    -----

<S>                                                   <C>      <C>      <C>      <C>      <C>      <C>
EXPLORATORY:
  Crude Oil ......................................        1      1.0       --       --       --       --
  Dry holes (a) ..................................        2      2.0        1      0.5        1      1.0
DEVELOPMENT:  (b)
  Crude oil ......................................       26     21.7       --       --       16     10.8
  Natural gas ....................................        8      6.5        3      3.0        3      1.5
  Dry holes ......................................        5      4.9        2      1.5        2      2.0
  Service wells ..................................        2      1.0       --       --        1      0.5
                                                      -----    -----    -----    -----    -----    -----

     Total .......................................       44     37.1        6      5.0       23     15.8
                                                      =====    =====    =====    =====    =====    =====
</TABLE>

(a)  1999 well was drilled in Tunisia, North Africa.

(b)  Included in drilling activities are wells deepened to a lower reservoir
     through existing well bores. In 1999, all wells under "Development" were
     deepenings within existing well bores.

      At December 31, 2000, we were drilling five gross wells, including two
gross wells (1.9 net wells) in Mississippi and three gross wells (2.0 net wells)
in Oklahoma.

RESERVES

      The following table summarizes our net proved crude oil and natural gas
reserves as of December 31, 2000, which have been reviewed by Ryder Scott
Company with regard to our Mississippi properties and Sproule Associates, Inc.
with regard to our Oklahoma properties. The other properties in the table are
related to our crude oil and natural gas reserves located in Texas which have
been audited, depending on location, by the independent engineers named in the
preceding sentence.



                                       16
<PAGE>   17




<TABLE>
<CAPTION>
                                                           AS OF DECEMBER 31, 2000
                                      ------------------------------------------------------------
                                         CRUDE           NATURAL        NET PROVED    PRESENT VALUE
                                          OIL              GAS           RESERVES       OF PROVED
                                        (MBBLS)          (MMCF)           (MBOE)        RESERVES
                                      ------------    ------------    ------------    ------------
                                                                                     (IN THOUSANDS)

<S>                                  <C>             <C>              <C>            <C>
OKLAHOMA PROPERTIES:
   Bumpass                                   2,975           6,326           4,029    $     46,118
   Cox Penn                                  3,145               0           3,145          24,268
   East Fitts                               23,036             449          23,111         130,192
   East Velma Middle Block                  10,920           4,087          11,601          92,696
   Eola                                      2,247           2,797           2,713          34,887
   North Alma Deese                          8,869               0           8,869          49,932
   Sholem Alechem                            6,011           3,552           6,603          54,249
   Tatums                                    3,530               5           3,531          27,752
   Other Oklahoma - operated                 2,630             147           2,655          12,424
   Other Oklahoma - non-operated             1,919           4,964           2,745          39,382
                                      ------------    ------------    ------------    ------------
      Total Oklahoma Properties             65,282          22,327          69,002         511,900
                                      ------------    ------------    ------------    ------------

MISSISSIPPI PROPERTIES:
   Brookhaven                                5,126             334           5,184          51,239
   Laurel                                    9,892               0           9,892          57,580
   Martinville                               3,984             199           4,017          28,743
   Soso                                      5,049             578           5,145          34,550
   Summerland                                3,979               0           3,979          22,404
   Other Mississippi                         1,396           2,550           1,820          25,296
                                      ------------    ------------    ------------    ------------
      Total Mississippi Properties          29,426           3,661          30,037         219,812
                                      ------------    ------------    ------------    ------------

   Other Texas Properties                    1,285           2,723           1,739          24,889
                                      ------------    ------------    ------------    ------------
TOTAL                                       95,993          28,711         100,778    $    756,601
                                      ============    ============    ============    ============
</TABLE>


     At December 31, 2000, we had net proved developed reserves of 69,928 MBOE
and net proved undeveloped reserves of 30,850 MBOE. The present value of proved
reserves of $756.6 million represented $520.9 million for the proved developed
reserves and $235.7 million for the proved undeveloped reserves. The present
value of proved reserves is based on year end market prices of $26.80 per barrel
for crude oil and $9.78 per MMbtu for natural gas. Market prices for crude oil
and natural gas have fluctuated significantly over the last three years. These
year end market prices are high in comparison to historical average crude oil
and natural gas prices in the most recent three-year period. At December 31,
1999, we reported total proved reserves of 113,886 MBOE, and the present value
of proved reserves was $790.2 million.

     Reserves declined from 1999 to 2000 due to reserves produced during 2000
and due to downward revisions in reserve estimates as set forth below. Reserve
estimates for the following properties are no longer included in proved reserves
because:

     o    We have no further plans to participate in future drilling on
          undeveloped acreage in the North Padre Island field located in Federal
          waters, offshore Texas. Therefore, the net 879 MMcf of natural gas
          reserves associated with this proved undeveloped drilling project has
          been removed.

     o    Our new management team believes that the characteristics associated
          with the Smackover formation in our East Texas field do not currently
          warrant drilling for the deeper undeveloped reserves in the Smackover
          formation in this field. The Smackover has historically tested sour
          gas, which requires gas processing and special transportation
          arrangements for marketing the gas and associated liquids. Proved net
          reserves of 1.5 MMBOE, associated with two proved undeveloped drilling
          projects, have been removed at year end 2000.

     o    Our new management has reviewed the recent horizontal drilling results
          in the Summerland Field, targeting thin, strong waterdrive, heavy oil
          productive sands. Because of the risk associated with continuing a
          program to horizontally drill wells in these types of reservoir sands
          for improved recoveries we will not actively pursue this project.
          Proved net reserves of 1.2 MMBOE, associated with three drilling
          projects on undeveloped acreage, have been removed at year end 2000.




                                       17
<PAGE>   18

     The remaining changes to our net proved reserve base have been a function
of reservoir performance and an increase in operating expenses during the year.
Operating costs have increased during the year 2000 due to increased fluid
production, utility costs, costs for well services and materials.

     There are numerous uncertainties inherent in estimating quantities of
proved crude oil and natural gas reserves, including many factors beyond our
control. The estimates of the reserve engineers are based on several
assumptions, including the following:

     o    future production;

     o    revenues;

     o    taxes;

     o    production costs;

     o    success of development drilling;

     o    development expenditures; and

     o    quantities of recoverable crude oil and natural gas reserves.

Any significant variance in these assumptions could materially affect the
estimated quantity and value of reserves set forth herein. In addition, our
reserves might be subject to revision based upon:

     o    actual production performance;

     o    results of future development;

     o    prevailing crude oil and natural gas prices; and

     o    other factors.

     In general, the volumes of production from crude oil and natural gas
properties decline as reserves are depleted. Except to the extent we acquire
additional properties or additional interests in existing properties containing
proved reserves or conduct successful exploration and development activities
associated with our proven and unproven reserves, or both, our proved reserves
will decline as reserves are produced. Future crude oil and natural gas
production is therefore highly capital intensive and dependent upon the level of
success in acquiring or finding additional reserves.

     For further information on reserves, costs relating to crude oil and
natural gas activities and results in operations from producing activities, see
"Supplementary Information Related to Oil and Gas Activities" appearing in Note
14 to our consolidated financial statements included in this Form 10-K.

ACREAGE

     The following table summarizes the developed and undeveloped acreage we
owned or leased at December 31, 2000:

<TABLE>
<CAPTION>
                                                          Developed         Undeveloped
                                                      ----------------    ----------------
                                                      Gross      Net      Gross      Net
                                                      ------    ------    ------    ------

<S>                                                   <C>       <C>       <C>       <C>
Mississippi ......................................    24,246    22,989    21,315    15,907
Oklahoma .........................................    38,463    29,218        60        60
Texas ............................................     4,860     3,678     1,196     1,119
Offshore Gulf of Mexico ..........................     5,760     2,269        --        --
                                                      ------    ------    ------    ------
          Total ..................................    73,329    58,154    22,571    17,086
                                                      ======    ======    ======    ======
</TABLE>




                                       18
<PAGE>   19

     At December 31, 2000, we also held a 45.8% working interest in an
exploratory permit in Tunisia, North Africa, covering approximately 1,130,000
gross acres.

TITLE TO PROPERTIES

     As is customary in the oil and gas industry, in many circumstances, we make
only a limited review of title to undeveloped crude oil and natural gas leases
at the time we acquire them. However, before we acquire developed crude oil and
natural gas properties, and before drilling commences on any leases, we cause a
thorough title search to be conducted, and any material defects in title are
remedied to the extent possible. To the extent title opinions or other
investigations reflect title defects, we, rather than the seller of the
undeveloped property, are typically obligated to cure any title defects at our
expense. We could lose our entire investment in any property we drill, if we
have a title defect of a nature that we could not remedy or cure. We believe
that we have good title to our crude oil and natural gas properties, some of
which are subject to immaterial encumbrances, easements and restrictions. The
crude oil and natural gas properties we own are also typically subject to
royalty and other similar non-cost bearing interests customary in the industry.
We do not believe that any of these encumbrances or burdens will materially
affect our ownership or use of our properties.

COMPETITION

     The crude oil and natural gas industry is highly competitive. We encounter
strong competition from major oil companies and independent operators in
acquiring properties and leases for the exploration for, and production of,
crude oil and natural gas. Competition is particularly intense with respect to
the acquisition of desirable undeveloped crude oil and natural gas properties.
The principal competitive factors in the acquisition of desirable undeveloped
crude oil and natural gas properties include the staff and data necessary to
identify, investigate and purchase these properties, and the financial resources
necessary to acquire and develop these properties. Many of our competitors have
financial resources, staff and facilities substantially greater than ours. In
addition, the producing, processing and marketing of crude oil and natural gas
is affected by a number of factors which are beyond our control, the effect of
which cannot be accurately predicted.

     The principal resources necessary for the exploration and production of
crude oil and natural gas are:

     o    leasehold prospects under which crude oil and natural gas reserves may
          be discovered;

     o    drilling rigs and related equipment to explore for these reserves; and

     o    knowledgeable personnel to conduct all phases of crude oil and natural
          gas operations.

We compete for these resources with both major crude oil and natural gas
companies and independent operators. Although we believe our current operating
and financial resources will be adequate to preclude any significant disruption
of our operations in the immediate future, the continued availability of these
materials and resources to us cannot be assured.

CUSTOMERS AND MARKETS

     Substantially all of our crude oil is sold at the wellhead at posted
prices, as is customary in the industry. In some circumstances, natural gas
liquids are removed from our natural gas production and are sold by us at posted
prices. During 2000, EOTT Energy Operating Limited Partnership accounted for 41%
of our revenues and Amoco Production Company accounted for 29% of our revenues.
In October 2000, we began selling our crude oil that had been previously sold to
Amoco to TEPPCO Crude Oil, L.P. and Sunoco, Inc. While we believe our
relationships with EOTT, TEPPCO and Sunoco have been and will continue to be
good, any loss of revenue from these customers due to nonpayment by the customer
would have an adverse effect on our net income and earnings per share on our
income statement and, ultimately, may affect our share price. In addition, any
significant late payment may adversely affect our short term liquidity position.

     Effective November 1, 2000, we entered into a 14-month crude oil purchase
agreement with EOTT. Under this crude oil purchase agreement, we committed the
majority of our crude oil production in Mississippi to EOTT through December 31,
2001 on a pricing basis of posting plus a premium with adjustment made for
gravity.




                                       19
<PAGE>   20

Additionally, we continue to sell EOTT approximately 50% of our heavy
Mississippi crude oil under a separate contract that is renewable on an annual
basis with similar pricing arrangements based on postings plus a premium with an
adjustment for gravity. This contract also sets a minimum well head price of
$8.50 per barrel for this heavy crude oil.

     The majority of crude oil production in Oklahoma is sold to TEPPCO Crude
Oil, L.P. and Sunoco, Inc. on a NYMEX pricing basis minus a discount with an
additional discount for fluctuations in the price for our sour oil. Our
contracts with Teppco and Sunoco expire on September 30, 2001. Pursuant to the
Amoco purchase and sale agreement entered into in November 1997, Amoco has
retained a right of first refusal to match, in all respects, a competitive bid
for the purchase on an annual basis of our crude oil through 2007.

     The sales prices we receive for crude oil and natural gas may vary
significantly during the year due to the volatility of the crude oil and natural
gas market, particularly during the cold winter and hot summer months. As a
result, we periodically enter into forward sale agreements or other arrangements
for a portion of our crude oil and natural gas production to hedge our exposure
to price fluctuations. Gains and losses on these forward sale agreements are
reflected in crude oil and natural gas revenues at the time of sale of the
related hedged production. While intended to reduce the effects of the
volatility of the prices received for crude oil and natural gas, these hedging
transactions may limit our potential gains if crude oil and natural gas prices
were to rise substantially over the price established by the hedge. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources - Hedging Activities and Other
Derivatives" and note 1 to our consolidated financial statements for more
information related to hedging.

OFFICE AND FIELD FACILITIES

     We currently lease 26,751 square feet for our executive and administrative
offices in Dallas, Texas, under a lease that continues through December 2005. We
lease field offices in Laurel, Mississippi, covering approximately 5,000 square
feet under a month-to-month lease. We are currently evaluating the Laurel lease
as well as other alternatives. We also lease office space in Ratliff City,
Oklahoma, covering approximately 10,000 square feet through January 2003.

GOVERNMENTAL REGULATION

     Crude oil and natural gas exploration, development and production are
subject to various types of regulation by local, state and federal agencies.
These laws and regulations govern, among other things:

     o    issuing permits and bonds in connection with drilling activities;

     o    imposing a production severance tax;

     o    regulating operations on secondary recovery projects;

     o    regulating the location of wells;

     o    regulating the method of drilling and casing wells;

     o    regulating the surface use and restoration of properties upon which
          wells are drilled; and

     o    regulating the plugging and abandonment of wells.

Our operations are also subject to various conservation laws and regulations in
which our properties are located, including those of Mississippi, Oklahoma and
Texas. These laws and regulations include the regulation of:

     o    the size of drilling and spacing units or proration units;

     o    the density of wells that may be drilled;

     o    unitization or pooling of crude oil and natural gas properties;





                                       20
<PAGE>   21

     o    maximum rates of production from crude oil and natural gas wells;

     o    restrictions on the venting or flaring of natural gas; and

     o    requirements regarding the ratability of production.

Some states allow the forced pooling or integration of tracts to facilitate
exploration while other states rely on voluntary pooling of land and leases. The
effect of these regulations is to limit the amount of crude oil and natural gas
we can produce from our wells and to limit the number of wells or the locations
at which we can drill. Failure to comply with such rules and regulations can
result in substantial penalties. The regulatory burden on the crude oil and
natural gas industry increases our cost of doing business and effects our
profitability. Because such rules and regulations are constantly amended or
reinterpreted, we are unable to predict the future cost or impact of complying
with such laws.

     Each state generally imposes a production or severance tax with respect to
production and sale of crude oil, natural gas and natural gas liquids within
their respective jurisdictions. For the most part, state production taxes are
applied as a percentage of production or sales. Currently, we are subject to
production tax rates of up to 6.2% in Mississippi and 7.2% in Oklahoma.

     Some of our operations are conducted on federal and Indian oil and gas
leases that are subject to a variety of regulations and rules published by the
United States Minerals Management Service and other federal agencies. For
offshore leasing operations, the Minerals Service issues detailed regulations
and orders which govern, among other things:

     o    the approval for exploration, development and production plans;

     o    the issuance of permits for drilling operations and drilling bonds;

     o    the engineering and construction specifications for offshore
          production facilities; and

     o    the plugging and abandonment of such wells.

With respect to gas royalty valuation, the Minerals Service has published final
rules that amend regulations governing valuation for royalty purposes of gas
produced from federal and Indian leases. The Minerals Service has also published
proposed rules to amend the current federal crude oil royalty valuation
regulations and the current Indian crude oil royalty valuation regulations. With
regards to the proposed rules, we cannot predict what action the Minerals
Service might take on these matters, nor can we predict at this stage of the
rulemaking proceedings how we might be affected by amendments to these
regulations. With regards to the other regulations and amendments thereto,
management believes that these regulations and amendments to the regulations
have not had a material adverse effect on our results of operations.

     The Federal Energy Regulatory Commission, in response to the Energy Policy
Act of 1992, has implemented regulations establishing an indexing system for
transportation rates for crude oil pipelines. The regulations would generally
index transportation rates to inflation. These regulations may affect the price
that we receive from the sale of crude oil due to a possible increase in the
cost of transporting oil to market. We are not able to predict with certainty
what effect, if any, these regulations will have on us, but other factors being
equal, the regulations may tend to increase transportation costs or reduce
wellhead prices for these commodities. The ultimate impact on us of these
complex and overlapping rules and regulations, many of which are repeatedly
subjected to judicial challenge and interpretation, cannot be predicted.

ENVIRONMENTAL REGULATIONS

     Our oil and gas operations and properties are subject to numerous federal,
state and local laws and regulations relating to environmental protection. These
laws and regulations may:

     o    require us to obtain permits before drilling;



                                       21
<PAGE>   22




     o    restrict the types, quantities and concentration of various substances
          that can be released into the environment through drilling and
          production activities;

     o    limit or prohibit drilling activities on some lands lying within
          wilderness, wildlife refuges or preserves, wetlands and other
          protected areas;

     o    restrict the discharge of produced waters and other oil and gas wastes
          into navigable waters;

     o    regulate the treatment, storage and disposal of hazardous waters; and

     o    regulate the remediation of contaminated sites.

In addition, these laws and regulations may impose substantial liabilities for
our failure to comply with them or for any contamination resulting from our
operations. We maintain insurance against losses or liabilities arising from our
operations in accordance with customary industry practices and in amounts we
believe reasonable. However, insurance is often not available against all
operational risks or is not economically feasible for us to obtain. If a
significant event occurs that imposes liability on us that is either not insured
or not fully insured, a material adverse effect on our financial condition and
results of operations could result.

     We take the issue of environmental responsibility very seriously and work
diligently to comply with applicable federal, state and local environmental
rules and regulations including but not limited to, the Oil Pollution Act of
1990, the Federal Water Pollution Control Act of 1972, the Comprehensive
Environmental Response, Compensation, and Liability Act, the Resource
Conservation and Recovery Act. Management believes compliance with such laws and
regulations has not had a material adverse effect on our operations or financial
condition in the past. To date, compliance with such laws and regulations has
not materially affected our operations or financial condition. However, because
environmental laws and regulations are becoming increasingly more stringent,
there can be no assurances that such laws and regulations or any environmental
law or regulation enacted in the future will not significantly affect our
operations or financial condition.

     A significant portion of our operations in Mississippi is conducted within
city limits. Each year we are required to meet tests of financial responsibility
to obtain permits to conduct new drilling operations. We are conducting a
voluntary program to remove inactive aboveground storage tanks from our well
sites and to replace them, as necessary, with newer aboveground storage tanks.

     Some states have enacted statutes governing the handling, treatment,
storage and disposal of waste containing naturally occurring radioactive
material. Naturally occurring radioactive material is present in varying
concentrations in subsurface and hydrocarbon reservoirs around the world and may
be concentrated in scale, film and sludge in equipment that comes in contact
with crude oil and natural gas production and processing streams. Mississippi
legislation prohibits the transfer of property for residential or other
unrestricted use if the property evidences concentrations of naturally occurring
radioactive material above prescribed levels because of crude oil and natural
gas production activities. We are voluntarily remediating naturally occurring
radioactive material concentrations identified at several fields in Mississippi.

EMPLOYEES

     At March 1, 2001, we had 98 employees associated with our operations,
including 21 field personnel in Mississippi and 27 field personnel in Oklahoma.
None of our employees is represented by a union. We consider our employee
relations to be satisfactory.


ITEM 3. LEGAL PROCEEDINGS

     Hicks Muse Lawsuits. We are the plaintiff in a lawsuit styled Coho Energy,
Inc. v. Hicks, Muse, et al, which we filed in the District Court of Dallas
County, Texas, 68th Judicial District filed on May 27, 1999. This lawsuit has
been removed to the United States Bankruptcy Court for the Northern District of
Texas, Dallas Division, where it currently is pending. The lawsuit alleges:




                                       22
<PAGE>   23

     o    breach of the written contract terminated by HM4 Coho L.P., a limited
          partnership formed by Hicks Muse on behalf of the Hicks, Muse, Tate &
          Furst Equity Fund IV, in December 1998;

     o    breach of the oral agreements reached with HM4 on the restructured
          transaction in February 1999; and

     o    promissory estoppel.

In the lawsuit, we have sought monetary damages of approximately $300 million.
Discovery is substantially complete and both sides have filed motions for
summary judgement, which were heard during January 2001. The Court has now ruled
on the motions. The Court has denied our motion for summary judgment, and has
granted, in part, and denied, in part, Hicks, Muse's motion. Based on these
orders, it appears that we will be able to go to trial on a claim for breach of
contract that has an actual damages of up to $165 million.

     This description is only a general description of the Hicks Muse lawsuit
and should not be relied on as conclusively stating all the alleged facts,
claims or circumstances surrounding the lawsuit. We are not able to evaluate the
recovery we might receive in the lawsuit. Additionally, our old shareholders are
eligible to receive 20% of any proceeds available from this lawsuit after fees
and expenses pursuant to our plan of reorganization.

     On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of
Hicks, Muse, Tate & Furst, filed a lawsuit in the United States District Court
of for the Northern District of Texas, Dallas Division against certain of our
former officers alleging, among other things, such officers made or caused to be
made false and misleading statements as to the proved oil and gas reserves
purportedly owned by us. The plaintiffs are asking for compensatory damages of
approximately $15 million plus punitive damages. Pursuant to our bylaws, we may
be required to indemnify such former officers against damages incurred by them
as a result of the lawsuit not otherwise covered by our directors' and officers'
liability insurance policy. The judge has dismissed certain claims and the case
is set for trial in the spring of 2002. We believe the lawsuit is without merit
and do not expect the outcome of the lawsuit to have a material adverse effect
on our financial position or results of operations.


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

         None.




                                       23
<PAGE>   24




                                     PART II

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

         Our common stock was, until June 7, 1999, listed on the Nasdaq Stock
Market under the symbol "COHO." Our common stock is currently traded on the
Nasdaq's OTC Bulletin Board under the symbol "CHOH." The following table shows
the high and low sale prices of our common stock over recent periods.

<TABLE>
<CAPTION>
                                                                HIGH                LOW
                                                                ----                ---
<S>               <C>                                         <C>                 <C>
1999
                  1st Quarter                                 $ 3 1/8             $  1/2
                  2nd Quarter                                   1                    1/32
                  3rd Quarter                                   1 5/8                7/32
                  4th Quarter                                     3/4                5/32
2000
                  1st Quarter                                 $   3/4             $   1/5
                  2nd Quarter                                  12                   2
                  3rd Quarter                                   8 1/4               6
                  4th Quarter                                   6 3/4               2 7/8
</TABLE>

     As a result of our financial condition and decreases in the market value of
our common stock during 1999, the Nasdaq Stock Market on March 8, 1999,
suspended trading of our common stock. As of the close of business on June 4,
1999, our common stock was delisted from Nasdaq. As a result of these actions,
our common stock is not currently listed but is trading over the counter. At
December 31, 2000, there were 191 holders of record of our common stock. We
believe we have approximately 5,523 beneficial holders of our common stock.

     Prior to March 31, 2000, the effective date of the plan of reorganization,
we had 25,603,512 shares of old common stock issued and outstanding. Old
shareholders received shares of new common stock on a basis of one share of new
common stock for 40 shares of old common stock on the effective date.

     We have never paid cash dividends on our existing common stock and we do
not intend to pay cash dividends on our new common stock. Because Coho Energy,
Inc. is a holding company, our ability to pay dividends depends on the ability
of our subsidiaries to pay cash dividends or make other cash distributions. Our
debt agreements generally prohibit the subsidiaries from paying dividends or
making cash distributions. Our board of directors has sole discretion over the
declaration and payment of future dividends. Any future dividends will depend
on:

     o    profitability;

     o    financial condition;

     o    cash requirements;

     o    future prospects;

     o    general business conditions;

     o    the terms of our debt agreements; and

     o    other factors our board of directors believes relevant.






                                       24
<PAGE>   25




ITEM 6. SELECTED FINANCIAL DATA

     The following selected consolidated financial data for each of the five
years in the period ended December 31, 2000 are derived from, and qualified by
reference to, our audited consolidated financial statements included in Item 8
of this Form 10-K. The information presented below should be read in conjunction
with our consolidated financial statements and the related notes and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" included in this Form 10-K. The selected consolidated financial data
presented below is not necessarily indicative of the future results of our
operations or financial performance.


<TABLE>
<CAPTION>
                                                                                        YEARS ENDED DECEMBER 31,
                                                                ----------------------------------------------------------------
                                                                   1996        1997          1998          1999          2000
                                                                ---------    ---------     ---------     ---------     ---------
                                                                          (IN THOUSANDS, EXCEPT EARNINGS PER SHARE AMOUNTS)
<S>                                                             <C>          <C>           <C>           <C>           <C>
STATEMENT OF EARNINGS DATA:
     Operating revenues ....................................    $  54,272    $  63,130     $  68,759     $  57,323     $  90,182
     Operating costs .......................................       13,875       15,970        26,859        21,155        29,320
     General and administrative expenses ...................        7,264        7,163         7,750         9,905         7,137
     Reorganization costs ..................................           --           --            --         3,123        12,004
     Allowance for bad debt ................................           --           --           894            --           765
     Depletion and depreciation ............................       16,280       19,214        28,135        13,702        15,316
     Writedown of crude oil and natural gas
           properties ......................................           --           --       188,000         5,433         3,027
     Net interest expense (a) ..............................        7,464       10,474        32,721        33,698        50,907
     Other expense .........................................           --           --         3,023         1,048            --
     Income tax expense (benefit) ..........................        3,483        4,021       (14,383)          (26)           --
     Net earnings (loss) before extraordinary items ........        5,906        6,288      (203,346)      (30,715)      (28,294)
     Net earnings (loss) ...................................        5,906        6,288      (203,346)      (30,715)      (32,722)
     Basic earnings (loss) before extraordinary
           items per common share(b) .......................    $   11.71    $    1.16     $ (317.68)    $  (47.99)        (1.98)
     Basic earnings (loss) per common share(b) .............    $   11.71    $    1.16     $ (317.68)    $  (47.99)        (2.29)
     Diluted earnings (loss) before extraordinary
           items per common share(c) .......................    $   11.61    $    1.13     $ (317.68)    $  (47.99)        (1.98)
     Diluted earnings (loss) per common share(c) ...........    $   11.61    $    1.13     $ (317.68)    $  (47.99)        (2.29)


OTHER FINANCIAL DATA:
     Capital expenditures ..................................    $  52,384    $  72,667     $  70,143     $   6,349     $  25,272
BALANCE SHEET DATA:
     Working capital (deficit)(d) ..........................    $   6,662    $  (2,021)    $(388,297)    $(407,490)    $  (2,647)
     Net property and equipment ............................      210,212      531,409       324,574       311,788       317,667
     Total assets ..........................................      230,041      555,128       350,068       348,801       366,791
     Long-term debt, excluding current portion .............      122,777      369,924            --            --       282,412
     Total shareholders' equity ............................       81,466      142,103       (61,243)      (91,958)       61,509
</TABLE>


(a)  Amount for 2000 includes interest expense of $36,192 and interest expense
     related to embedded derivative of $15,163, partially offset by interest
     income of $448.

(b)  Basic per share amounts have been computed by dividing net earnings after
     preferred dividends by the weighted average number of shares outstanding:
     504 in 1996; 542 in 1997; 640 in 1998; 640 in 1999; and 14,266 in 2000.

(c)  Diluted per share amounts have been computed by dividing net earnings after
     preferred dividends by the weighted average number of shares outstanding
     including common stock equivalents, consisting of stock options and
     warrants, when their effect is dilutive: 509 in 1996; 558 in 1997; 640 in
     1998; 640 in 1999; and 14,266 in 2000.

(d)  Amounts for 1998 and 1999 include $384,031 and $388,685, respectively,
     related to the current portion of long-term debt. The working capital
     deficit as of December 31, 1999 also includes liabilities subject to
     compromise as a result of the bankruptcy filing.


                                       25
<PAGE>   26

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

     The following discussion should be read in conjunction with our
consolidated financial statements included in this Form 10-K. Some information
contained in this Form 10-K, including information with respect to our plans and
strategy for our business, are forward-looking statements. For more information
about the limitations associated with these types of statements, see the section
called " Forward-Looking Statements."

GENERAL

     We were incorporated in June 1993 under the laws of the State of Texas and
currently conduct a majority of our operations as an independent energy company
through Coho Resources, Inc. and its subsidiaries.

     Our crude oil activities are concentrated principally in Mississippi and
Oklahoma. We commenced operations in Mississippi in the early 1980s. We acquired
our Oklahoma properties from Amoco Production Company in December 1997. At
December 31, 2000, approximately 95% of our total proved reserves were comprised
of crude oil. Our operating revenues result solely from crude oil and natural
gas sales, with crude oil sales representing approximately 77% of production
revenues for 1998, 90% of production revenues for 1999 and 91% of production
revenues for 2000. Natural gas sales represented approximately 23% of production
revenues for 1998, 10% of production revenues for 1999 and 9% of production
revenues for 2000. Approximately 60% of natural gas sales revenues during 1998
were attributable to the gas properties located in Monroe, Louisiana, which we
sold in December 1998.

     In August 1999, we filed a voluntary petition for relief under Chapter 11
of the United States Bankruptcy Code in order to facilitate a restructuring of
our long-term debt. Our plan of reorganization was consummated on March 31,
2000. As a result of the reorganization, our former principal bondholders and
their affiliates own 88% of our new common stock. A new management team and a
new board of directors have been directing our operations since we emerged from
bankruptcy.


RESULTS OF OPERATIONS

     SELECTED OPERATING DATA

<TABLE>
<CAPTION>
                                                              1998        1999        2000
                                                            --------    --------    --------
<S>                                                         <C>         <C>         <C>
PRODUCTION:
   Crude oil (Bbl/day) .................................      13,889       9,159       9,658
   Natural gas (Mcf/day) ...............................      22,260       7,146       5,702
   BOE (Bbl/day) .......................................      17,599      10,350      10,608
AVERAGE SALES PRICES:
   Crude oil (per Bbl) .................................    $  10.40    $  15.40    $  23.31
   Natural gas (per Mcf) ...............................        1.98        2.24        3.73
PER BOE DATA:
   Production costs ....................................    $   3.65    $   4.82    $   6.06
   Production taxes ....................................         .53         .78        1.49
   Depletion ...........................................        4.38        3.63        3.94
PRODUCTION REVENUES (IN THOUSANDS):
   Crude oil ...........................................    $ 52,689    $ 51,469    $ 82,390
   Natural gas .........................................      16,070       5,854       7,792
                                                            --------    --------    --------

        Total production revenues ......................    $ 68,759    $ 57,323    $ 90,182
                                                            ========    ========    ========
</TABLE>







                                       26
<PAGE>   27



2000 COMPARED WITH 1999

     Operating Revenues. During 2000, production revenues increased 57% to $90.2
million as compared to $57.3 million in 1999. This increase was principally due
to a 5% increase in crude oil production, a 51% increase in the price received
for crude oil and a 67% increase in the price received for natural gas,
including hedging losses discussed below, partially offset by a 20% decrease in
natural gas production.

     During 1999, we experienced overall crude oil production declines in our
operated properties due to capital constraints as discussed below in "1999
Compared With 1998." During 2000, we experienced a 5% increase in daily crude
oil production as compared to 1999 due to several factors, including:

     o    returning substantially all previously shut-in wells to active
          service;

     o    recompleting inactive wells and marginal producers;

     o    repairing wells that were previously uneconomical to repair due to
          depressed crude oil prices; and

     o    increasing drilling activity on our operated properties.

     The 20% decrease in natural gas production is primarily due to the natural
declines on our operated and non-operated gas properties. The effect of natural
production declines was partially offset by temporary increases in production
due to several recompletions on our operated and nonoperated gas properties that
were followed by rapid declines.

     We experienced a loss of production on our Oklahoma crude oil and natural
gas properties on December 27, 2000 due to a full power outage resulting from an
ice storm in southern Oklahoma. The main power was restored on January 1, 2001;
however, we continued to experience a partial loss of production through January
23, 2001 at which time all wells were restored to production. We estimate the
loss of production to be approximately 20,200 BOE during the last four days of
December 2000 and approximately 13,300 BOE during January 2001.

     Average crude oil prices increased 51% during 2000 compared to the same
period in 1999, primarily due to strong demand for crude oil during 2000. During
the first quarter of 1999, substantially all of our crude oil was sold under
contracts that were keyed off of posted crude oil prices. Subsequent to March
1999, substantially all of our Oklahoma crude oil has been sold under contracts
that keyed off of the NYMEX price. Our overall average crude oil price per Bbl
during 2000 was $23.31, including hedging losses of $2.79 per Bbl as discussed
below, which represented a discount of 23% to the average NYMEX price in 2000.

     Our realized price for our natural gas increased 67% from $2.24 per Mcf in
1999 to $3.73 per Mcf in 2000, including hedging losses of $0.26 per Mcf as
discussed below, due to an increase in demand for natural gas during 2000.

     Production revenues for 2000 included crude oil hedging losses of
$9,856,000 ($2.79 per BOE) and natural gas hedging losses of $544,000 ($0.26 per
Mcf). Production revenues for 1999 did not include any crude oil or natural gas
hedging gains or losses.

     Expenses. Production expenses were $23.5 million for 2000 compared to $18.2
million for 1999. The increase in expenses from 1999 to 2000 is due primarily
to:

     o    increased electrical costs of approximately $1.8 million due to
          greater fluid movement and higher electrical rates;

     o    increased chemical costs of approximately $609,000 due to increases in
          production; and

     o    increased well repair costs of approximately $2.2 million due to more
          extensive repair work and costs to return shut in wells, inactive
          wells and marginal wells to production and increased costs between
          years for labor, materials and rigs related to well repair costs of
          approximately 10%, 5% and 20%, respectively.




                                       27
<PAGE>   28

On a BOE basis, production costs increased 26% to $6.06 per BOE in 2000 compared
to $4.82 per BOE in 1999. On a BOE basis, production costs increased because the
increase in production did not keep pace with the increases in costs discussed
above. Additionally, our well repair costs were higher in 2000 because we
changed our approach to well repairs. In the past, our approach was generally to
only repair any immediate problems with a well. We now evaluate the total
condition of the well and repair any immediate problems as well as replace worn
parts that may cause additional problems within the next year. Although the
upfront repair costs are higher, future repair costs should decrease because the
rig cost, which is generally a major cost in well repair work, is only incurred
once and downtime for well repairs should decrease.

     Production taxes increased $2.8 million or 97% to $5.8 million during 2000
as compared to $2.9 million during 1999. This increase is due to increased crude
oil production and due to higher realized prices. On a BOE basis, production
taxes increased 91% to $1.49 per BOE during 2000 as compared to $.78 per BOE
during 1999 due to higher realized prices.

     General and administrative costs decreased $2.8 million or 28% between the
comparable periods. This decrease is primarily due to:

     o    reductions of $2.4 million in employee-related costs, primarily due to
          the termination of officers and employees in April 2000 in conjunction
          with our plan of reorganization;

     o    increases in cost recoveries from working interest owners due to an
          increase in well activity; and

     o    capitalization of $765,000 of salaries and salary related costs
          associated with exploration and development activities.

These decreases were partially offset by increases in professional fees,
primarily due to Hicks Muse litigation costs.

     State income tax penalties of $1.0 million for 1999 resulted from
approximately $4 million in Louisiana state income taxes which were due on April
15, 1999, resulting from the gain on the December 1998 sale of the Monroe gas
field. The past due taxes include the accrual of the maximum penalty of 25% of
the taxes due.

     Interest expense increased 6% to $36.2 million in 2000 as compared to $33.9
million in 1999. The following is a summary of interest expense between
comparable periods:

<TABLE>
<CAPTION>
                                                        1999        2000
                                                      --------    --------
                                                         (in thousands)
<S>                                                   <C>         <C>
Old bank group loan ..............................    $ 23,673    $  7,983
Old bond .........................................       9,275          --
New credit facility ..............................          --      13,434
Standby loan .....................................          --      10,090
Amortization of debt issuance costs ..............         604       4,597
Miscellaneous ....................................         392          88
                                                      --------    --------
                                                      $ 33,944    $ 36,192
                                                      ========    ========
</TABLE>


The increase for the comparable periods relates to several factors including the
following:

     o    an effective interest rate of 18.04% on the original $72 million
          standby loan issued March 31, 2000;

     o    an effective rate of 23.92% on the paid-in-kind interest standby loan
          issued September 29, 2000; and

     o    higher debt issuance amortization expense resulting from $33.8 million
          in debt issuance costs on our new debt, including $24.2 million
          related to the issuance of common stock in connection with the standby
          loan.

These increases were partially offset by:



                                       28
<PAGE>   29

     o    lower interest expense due to a reduction in our debt on March 31,
          2000 resulting from the reorganization,

     o    discontinuance of the accrual of interest on our old unsecured bonds
          as a result of our bankruptcy filing (approximately $3.5 million of
          additional interest expense would have been recognized during the
          first quarter of 2000 compared to $5.5 million for 1999, if not for
          the discontinuance of such interest expense accrual); and

     o    higher interest rates and interest on past due interest on our old
          bank loan for a shorter period in 2000 as compared to 1999.

The average interest rate on outstanding indebtedness was 12.48% in 2000,
excluding interest expense related to the embedded derivative, compared to 8.55%
in 1999.

     Interest expense related to the embedded derivative for the year ended 2000
of $15.2 million relates to the change in estimated future additional interest
payments calculated on the standby loan. The aggregate amount of the additional
interest payments were estimated at March 31, 2000 for the original $72 million
standby loan and at September 29, 2000 for the $5.4 million paid-in-kind
interest standby loan using the future crude oil and natural gas price curves as
of such dates. The aggregate amount of additional interest payments was
redetermined at December 31, 2000 using the then current crude oil and natural
gas curves. The increase of $15.2 million in the aggregate amount of additional
interest payments based on the December 31, 2000 price curves as compared to the
aggregate amount of additional interest payments based on the March 31, 2000 and
September 29, 2000 price curves was charged to interest expense during 2000.

     Depletion and depreciation expense increased 11% to $15.2 million in 2000
from $13.7 million in 1999. This increase is primarily the result of increased
production volumes and an increased depletion and depreciation rate per BOE,
which was $3.94 in 2000, compared with $3.63 in 1999. The depletion and
depreciation rate per BOE increased due to an increase in depletable costs and
due to a decline in total proved reserves. During 2000, we reclassified unproved
property costs totaling $25.7 million that had been excluded from depletable
costs as of December 31, 1999 to costs subject to depletion at December 31,
2000. These costs were reclassified because certain of the unproved projects
were not viewed as economically attractive by our new management team and will
not be performed in the foreseeable future. See "Item 2. Business and Properties
- Oil and Gas Operations-Reserves" for a discussion of the decline in total
proved reserves.

     We have used the full-cost method of accounting for our investment in crude
oil and natural gas properties. In accordance with generally accepted accounting
principles, at a point in time coinciding with the quarterly and annual
reporting periods, we must test the carrying value of our crude oil and natural
gas properties, net of related deferred taxes, against the "cost center
ceiling." The "cost center ceiling" is a calculated amount based on estimated
reserve volumes valued at then-current realized prices held flat for the life of
the properties discounted at 10% per annum plus the lower of cost or estimated
fair value of unproved properties. If the carrying value exceeds the cost center
ceiling, the excess must be expensed in that period and the carrying value of
the oil and gas reserves lowered accordingly. Amounts required to be written off
may not be reinstated for any subsequent increase in the cost center ceiling. No
writedowns of this kind were required on our United States properties in 2000 or
1999.

     We have decided to discontinue our participation in the exploration of two
Tunisia, North Africa permits. In February 2001, the two subsidiaries that own
these permits filed for protection under chapter 11 of the United States
Bankruptcy Code to preserve our ownership in these permits under the protection
of the bankruptcy court while we try to negotiate sales of our interests in the
permits to a third party or parties and to reach settlements with respect to our
obligations under the permits. As a result, we took a writedown of $3.0 million,
representing our remaining carrying costs on these permits, during the fourth
quarter of 2000. See "Subsequent Event - Discontinuation of Tunisian Operations"
for further discussion on our Tunisian operations.

     Reorganization costs increased $8.9 million to $12.0 million in 2000 as
compared to $3.1 million in 1999. This increase relates to:

     o    professional fees for consultants and attorneys assisting in the
          negotiations associated with reorganization alternatives and approval
          and implementation of our plan of reorganization;



                                       29
<PAGE>   30

     o    termination benefits for severed employees;

     o    payments and accrual of settlement amounts for officer employment
          agreements and officer severance agreements which were rejected in the
          plan of reorganization;

     o    payments and accrual of amounts made under our retention bonus plan;
          and

     o    provisions for settlements of disputed bankruptcy claims and other
          costs to effect the plan of reorganization.

     Our net operating loss carryforwards for United States and Canadian federal
income tax purposes were approximately $118.5 million at December 31, 2000 and
expire between 2009 and 2020. Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes," requires that the tax benefit of those net
operating loss carryforwards be recorded as an asset to the extent that
management assesses the utilization of those net operating loss carryforwards to
be more likely than not. A valuation allowance has been established for the
entire net deferred tax asset balance of these net operating loss carryforwards
as it is uncertain whether they will be used before they expire. We experienced
an "ownership change" (within the meaning of IRC section 382) on the effective
date of the plan of reorganization as a result of the issuance of new common
stock to certain holders of claims. Our ability to use any pre-effective date
NOLs and capital loss carryovers to offset income in any post-effective date
taxable year (and in the portion of the taxable year of the ownership change
following the effective date) to which such a carryover is made (subject to
various exceptions and adjustments) will be limited, resulting in an estimated
$33.0 million of NOL's which are expected to expire due to the IRC section 382
limitation.

     Due to the factors discussed above, our net loss for 2000 was $32.7
million, as compared to a net loss of $30.7 million for 1999. The losses include
writedowns of our Tunisian oil and gas properties of $3.0 million and $5.4
million for 2000 and 1999, respectively.

1999 COMPARED WITH 1998

     Operating Revenues. During 1999, production revenues decreased 17% to $57.3
million as compared to $68.8 million in 1998. This decrease was principally due
to a 34% decrease in crude oil production and a 68% decrease in natural gas
production, substantially offset by increases of 48% in the price received for
crude oil and 13% in the price received for natural gas, including hedging gains
and losses discussed below.

     The 68% decrease in daily natural gas production during 1999 was primarily
due to the December 1998 sale of the Monroe field gas properties which accounted
for 67% of our natural gas production during 1998. The 34% decrease in daily
crude oil production during 1999 is due to overall production declines in the
Mississippi and Oklahoma properties that we operate. Due to our capital
constraints caused by the decline in crude oil prices during 1998, we:

     o    significantly reduced both minor and major well repairs and drilling
          activity on our operated properties during the last five months of
          1998;

     o    ceased all well repairs and drilling activity in December 1998; and

     o    halted production on wells which were uneconomical due to depressed
          crude oil prices.

All of these actions contributed to our overall production declines. From May
1999 through December 1999 we used working capital provided by operations to
perform well repair work to return some of our shut-in wells to production in
response to the improved crude oil prices in the second quarter of 1999.

     Average crude oil prices increased 48% during 1999 compared to the same
period in 1998. During 1998 and the first quarter of 1999, substantially all of
our crude oil was sold under contracts which were keyed off of posted crude oil
prices. Beginning in April 1999, we entered into a new crude oil contract for
substantially all of our Oklahoma crude oil, now keyed off of the NYMEX price,
which resulted in a net increase in our realized price. Our overall average
crude oil price per Bbl was $15.40, which represented a discount of 20% to the
average NYMEX price in 1999.




                                       30
<PAGE>   31

     Our realized price for our natural gas, including hedging losses discussed
below, increased 13% from $1.98 per Mcf in 1998 to $2.24 per Mcf in 1999 due to
an increase in demand for natural gas during 1999.

     Production revenues for 1999 and 1998 did not include any crude oil hedging
gains or losses. Production revenues in 1999 did not include any natural gas
hedging gains or losses compared to natural gas hedging gains of $488,000 ($0.06
per Mcf) for 1998.

     Expenses. Production expenses, including production taxes, were $21.2
million for 1999 compared to $26.9 million for 1998. The decrease in expenses
between years is primarily due to:

     o    decreased production;

     o    decreased production taxes; and

     o    the December 1998 sale of the Monroe properties.

On a BOE basis, production costs increased 34% to $5.60 per BOE in 1999 compared
to $4.18 per BOE in 1998. On a BOE basis, the increase in production costs is
primarily due to a decrease in production volumes, which resulted in a higher
fixed cost per BOE, and $3.3 million of well repair work performed during the
last half of 1999 to return shut-in wells to production. Additionally, severance
taxes increased $0.25 per BOE during 1999 as compared to 1998 due to higher
price realization. The well repair work represented an accumulation of projects
because we had reduced both minor and major well repairs during the last five
months of 1998 and ceased substantially all well repair work in December 1998
due to depressed oil prices.

     General and administrative costs increased $2.2 million or 28% between the
comparable periods. This increase is primarily due to the expensing of all
salaries and other general and administrative costs associated with exploration
and development activities during 1999 as compared to the capitalization of $5.7
million of these costs in 1998. Total general and administrative costs,
excluding capitalization of administrative costs associated with exploration and
development activities, decreased $3.6 million or 27% between the comparable
periods. This decrease is primarily due to:

     o    cost reductions associated with the Monroe field sale;

     o    reductions in employee-related costs due to staff attrition;

     o    reductions in estimated franchise tax accruals as a result of our
          losses in 1998; and

     o    reductions in professional fees and general corporate costs.

These decreases were partially offset by lower cost recoveries from working
interest owners due to a decrease in well activity.

     State income tax penalties of $1.0 million for 1999 result from
approximately $4 million in Louisiana state income taxes which were due on April
15, 1999, resulting from the gain on the December 1998 sale of the Monroe gas
field. The past due taxes include the accrual of the maximum penalty of 25% of
the taxes due.

     Interest expense increased 3% in 1999 compared to 1998 primarily as a
result of higher interest rates from payment defaults and debt acceleration,
partially offset by the discontinuance of interest expense accruals on our
unsecured debt. On August 24, 1999, we discontinued the accrual of interest on
our unsecured debt as a result of our Chapter 11 filing. We would have
recognized approximately $5.7 million of additional interest expense in 1999,
including $2.2 million of interest on our old bonds that would have been due on
October 15, 1999, if not for the discontinuation of these interest expense
accruals. The average interest rate on outstanding indebtedness was 8.55% in
1999, compared to 8.07% in 1998.

     Depletion and depreciation expense decreased 51% to $13.7 million in 1999
from $28.1 million in 1998. This decrease is primarily the result of decreased
production volumes and a decreased depletion and depreciation rate per BOE,
which was $3.63 in 1999, compared with $4.38 in 1998. The depletion and
depreciation rate per BOE




                                       31
<PAGE>   32

decreased between 1998 and 1999 due to the writedowns of oil and gas properties
in 1998 as discussed in the next paragraph.

     During 1998, the carrying values related to our United States properties
exceeded the cost center ceilings, resulting in non-cash writedowns of our crude
oil and natural gas properties of $188 million. These writedowns resulted from
the declines in crude oil prices in 1998. No writedowns of this kind were
required on our United States properties in 1999.

     In June 1999, we commenced drilling an exploratory well on our Anaguid
permit in Tunisia, North Africa, due to our obligation under the permit. In
September 1999, we tested the well and determined that the well would not
produce sufficient quantities of crude oil to justify further completion work on
it. As a result, we took a writedown of our Tunisian properties of $5.4 million
during the third quarter of 1999.

     Reorganization costs of $3.1 million in 1999 relate to professional fees
for consultants and attorneys assisting us in the negotiations associated with
our financing and reorganization alternatives and are partially offset by
interest income earned since August 23, 1999, on accumulated cash.

     Due to the factors discussed above, our net loss for 1999 was $30.7
million, as compared to a net loss of $203.3 million for 1998. The 1999 loss
includes a writedown of our Tunisian oil and gas properties of $5.4 million and
the 1998 loss includes writedowns of our United States crude oil and natural gas
properties of $188.0 million.

LIQUIDITY AND CAPITAL RESOURCES

     Reorganization. On August 23, 1999, we and our wholly-owned subsidiaries,
Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho
Louisiana Production Company and Interstate Natural Gas Company, filed a
voluntary petition for relief under Chapter 11 of the U. S. Bankruptcy Code. We
then filed a plan of reorganization that was confirmed by the bankruptcy court
on March 20, 2000. On March 31, 2000, the plan of reorganization was consummated
and we emerged from bankruptcy.

     The reorganized value of our assets exceeded the total of all postpetition
liabilities and allowed claims; therefore, we did not qualify for fresh-start
accounting. We recorded the following transactions to effect our plan of
reorganization consummated on March 31, 2000:

     o    The borrowing of $183.0 million under our new credit facility.

     o    The borrowing of $72.0 million under the standby loan and the issuance
          of 2,694,841 shares of new common stock as debt issuance costs valued
          at $24.2 million.

     o    Repayment of borrowings outstanding under the old bank credit facility
          together with accrued interest and fees totaling $260.2 million,
          resulting in a $303,000 loss on extinguishment of debt.

     o    Conversion of the old bonds into 15,362,107 shares of new common
          stock, representing 82% of the new common stock. Although the old
          bonds were paid no more than in full, we did realize a loss on
          extinguishment of debt of $4.1 million because our carrying value of
          the old bonds was less than the allowed claim, primarily due to
          unamortized debt issuance costs.

     o    Provision of $1.6 million to allow for settlement of disputed claims.

     Substantially all of the bankruptcy claims and bankruptcy costs were paid
during 2000 with a final installment payment on unsecured claims being paid on
January 2, 2001. Priority tax claims totaling approximately $5.2 million
received five-year, interest-bearing promissory notes under our plan of
reorganization.

     As a result of the reorganization, our former bondholders and their
affiliates own approximately 88% of our new common stock and own $65.5 million
of the outstanding notes issued under the original $72 million standby loan.

     Capital Sources. During 2000, cash flow provided by operating activities
was $9.9 million compared with cash flow provided by operating activities of
$14.9 million for the same period in 1999. Operating revenues, net of lease





                                       32
<PAGE>   33

operating expenses, production taxes and general and administrative expenses,
increased $27.5 million from $26.3 million in 1999 to $53.7 million in 2000,
primarily due to:

     o    price increases between such comparable periods of 51% and 67% for
          crude oil and natural gas, respectively;

     o    increases in crude oil production; and

     o    reductions in general and administrative expenses.

The increases in net operating revenue as a result of these price and production
increases and general and administrative expense reductions were partially
offset by increases in production expenses and production taxes between
comparable periods. We also incurred costs totaling $12.0 million during 2000
related to reorganization costs. Changes in operating assets and liabilities
used $11.7 million of cash for operating activities for 2000, compared to $25.8
million of cash for operating activities provided for the same period in 1999,
primarily due to payment of $18.5 million in accrued interest payable and the
reclassification of $4.1 million of accrued state income taxes and penalties
from liabilities subject to compromise to long-term debt, partially offset by
increases in accrued reorganization costs, and other accrued liabilities and
increased accounts receivables from purchasers due to higher crude oil and
natural gas prices. See "Results of Operations" for a discussion of operating
results.

     Working Capital. We had a working capital deficit of $2.6 million at
December 31, 2000 compared to working capital, before liabilities subject to
compromise, of $16.2 million at December 31, 1999. The decrease in working
capital relates to several factors including the following:

     o    Cash balances on hand decreased from $18.8 million at December 31,
          1999 to $6.7 million at December 31, 2000. The decrease in cash is
          primarily due to the utilization of cash accumulated during bankruptcy
          to consummate the reorganization.

     o    Current liabilities increased from $15.2 million at December 31, 1999
          to $22.4 million at December 31, 2000 due to several factors
          including:

          o    the reclassification of $1.4 million of liabilities subject to
               compromise to current liabilities as a result of our emergence
               from bankruptcy;

          o    an increase of $2.6 million in trade payables primarily due to
               increased drilling and well repair activities subsequent to our
               emergence from bankruptcy;

          o    an increase of $1.3 million in accrued reorganization costs;

          o    an increase of $1.0 million in current long-term debt related to
               the current maturities under the five-year notes to be issued in
               settlement of priority tax claims;

          o    an increase of $1.2 million in current environmental liabilities
               related to the bankruptcy claims; " an increase of $507,000 in
               accrued liabilities related to a reserve established for disputed
               claims settlements;

          o    an increase of $3.4 million in accrued liabilities related to
               operations; and

          o    an increase of $900,000 in accrued liabilities related to hedging
               losses.

The above factors were partially offset by a reduction in accrued interest of
$6.1 million related to our bank credit facilities.

     Credit Facilities. We and some of our subsidiaries were parties to an old
bank group loan agreement. Borrowings outstanding under the old bank group loan,
together with accrued interest and reasonable fees totaling $260.2 million, were
paid on March 31, 2000. We obtained the funds necessary for the payment of the
old bank group loan through the combination of borrowings under the new senior
revolving credit facility, borrowings under the standby loan and from cash on
hand.

     Additionally, we owed approximately $162 million of principal and accrued
interest under our old bond indenture. Under the plan of reorganization, these
old bonds and accrued interest were converted into 15,362,107 shares of new
common stock.




                                       33
<PAGE>   34

     The new senior revolving credit facility was obtained from a syndicate of
lenders led by The Chase Manhattan Bank, as agent for the new lenders, and has a
principal amount of up to $250 million. The new credit facility limits advances
to the amount of the borrowing base, which is currently at $205 million. At
December 31, 2000, $180 million was outstanding under this bank facility. The
borrowing base is the loan value assigned to the proved reserves attributable to
our oil and gas properties. The new credit facility is subject to semiannual
borrowing base redeterminations each April 1 and October 1, based on our reserve
reports, and will be made at the sole discretion of the lenders. We or Chase may
each request one additional borrowing base redetermination during any calendar
year.

     Interest on advances under the new credit facility will be payable on the
earlier of the expiration of any interest period under the new credit facility
or quarterly. Amounts outstanding under the new credit facility will accrue
interest at our option at either the Eurodollar rate, which is the annual
interest rate equal to the London interbank offered rate ("LIBOR") for deposits
in United States dollars that is determined by reference to the Telerate Service
or offered to Chase plus an applicable margin (currently 3%), or the prime rate,
which is the floating annual interest rate established by Chase from time to
time as its prime rate of interest plus an applicable margin (currently 2%). All
outstanding advances under the new credit facility are due and payable on March
31, 2003.

The new credit facility has been secured by granting Chase the following
collateral for the benefit of the lenders:

     o    first and prior security interests in the issued and outstanding
          capital stock and other equity interests of our material subsidiaries;

     o    first and prior mortgage liens and security interests covering proved
          mineral interests selected by Chase having a present value, as
          determined by Chase, of not less than 85% of the present value of all
          our proved mineral interests evaluated by the lenders for purposes of
          determining the borrowing base; and

     o    first and prior security interests in our other tangible and
          intangible assets.

The new credit agreement contains financial and other covenants including:

     o    maintenance of required ratios of cash flow to interest expense paid
          or payable in cash (2 to 1 for the average of the last four
          consecutive quarters most recently ended December 31, 2000, gradually
          increasing to 3 to 1 for quarters ending after January 1, 2002),
          senior debt to cash flow required (not to exceed 5 to 1 for the
          average of the last four consecutive quarters most recently ended
          December 31, 2000, gradually decreasing to 3.5 to 1 for any quarter
          ending after January 1, 2002), and current assets (including unused
          borrowing base) to current liabilities required (throughout the term
          of the credit agreement, to be 1 to 1 as of the end of each quarter);

     o    restrictions on the payment of dividends; and

     o    limitations on the incurrence of additional indebtedness, the creation
          of liens and the incurrence of capital expenditures.

The lenders received an additional $5.8 million of closing fees in addition to
expense reimbursements.

     The standby loan was made under a senior subordinated note facility under
which we issued $72 million of senior subordinated notes to PPM America, Inc.,
Appaloosa Management, L.P., Oaktree Capital Management, L.L.C., Pacholder
Associates, Inc. and their respective assignees. Our rights and responsibilities
and those of the standby lenders are governed by a standby loan agreement which
was executed and delivered on March 31, 2000.

     Debt under the standby loan agreement is evidenced by notes maturing March
31, 2007 and bearing interest at a minimum annual rate of 15% and payable in
cash semiannually. After March 31, 2001, additional semiannual interest payments
will be payable in an amount equal to 1/2% for every $0.25 that the "actual
price" for our oil and gas production exceeds $15 per barrel of oil equivalent
during the applicable semiannual interest period, up to a maximum of 10%
additional interest per year. The "actual price" for our oil and gas production
is the weighted average price received by us for all our oil and gas production,
including hedged and unhedged production, net of hedging costs, in dollars per
barrel of oil equivalent using a 6:1 conversion ratio for natural gas. The
actual price will be calculated over a six-month measurement period ending on
the date two months before the applicable interest






                                       34
<PAGE>   35

payment date. Additionally, upon an event of default occurring under the standby
loan, interest will be payable in cash, unless otherwise required to be
paid-in-kind, at a rate equal to 2% per year over the applicable interest rate.
Interest payments under the standby loan may be paid-in-kind subject to the
requirements of the intercreditor arrangement between the standby lenders and
the lenders under the new credit agreement. "Paid-in-kind" refers to the payment
of interest owed under the standby loan by increasing the amount of principal
outstanding through the issuance of additional standby loan notes, rather than
paying the interest in cash. The semiannual standby loan interest payment due on
September 29, 2000 was paid-in-kind and has been reflected as an increase in
long-term debt.

     The additional semiannual interest payment feature of the standby loan
agreement based on the actual price received for our oil and gas production, as
discussed above, is considered an embedded derivative instrument. The additional
interest cost associated with this embedded derivative instrument is calculated
at the origination of each loan and at each future balance sheet date. The
aggregate amount of the additional interest payments on the original $72 million
standby loan was estimated at its inception date, using the future crude oil and
natural gas price curves as of such date. These estimated additional interest
payments were added to interest payments due based on the minimum annual rate at
15% to determine an effective interest rate of 18.04% for the term of the
original $72 million standby loan. In addition, the same procedures were applied
to the standby loan of $5.4 million issued on September 29, 2000 to determine an
effective rate of 23.92% for the term of this loan. The aggregate amount of the
additional interest payments due on each loan was redetermined at December 31,
2000 using the then current future crude oil and natural gas price curves. The
difference of $15.2 million in the amount of additional interest payments based
on the December 31, 2000 price curves as compared to the aggregate amount of
additional interest payments based on the price curves at the inception date of
each loan was reflected as an increase in the standby loan debt and a charge to
interest expense during 2000. The additional interest expense may continue to
have significant volatility from period to period based on the changes in the
futures price curves from period to period. For further discussion on the future
volatility of interest expense, see " Hedging Activities and Other Derivatives".

     Payment of the standby loan notes will be expressly subordinate to payments
in full in cash of all obligations arising in connection with the new credit
facility. After the initial 12-month period, cash interest payments may be made
only to the extent by which EBITDA, or earnings before interest, tax,
depreciation and amortization expense, on a trailing four-quarter basis exceed
$65 million. The new credit agreement also prohibits us from making any cash
interest payments on the standby loan indebtedness if the outstanding
indebtedness under both the new credit facility and the standby loan exceeds
3.75 times EBITDA for the trailing four quarters. We do not currently meet the
requirements to make cash interest payments on the standby loan indebtedness. We
may prepay the standby loan notes at the face amount, in whole or in part, in
minimum denominations of $1,000,000, plus either a standard make-whole payment
at 300 basis points over the "treasury rate" for the first four years, beginning
in the fifth year, a prepayment fee of 7.5% of the principal amount being
prepaid; in the sixth year, a prepayment fee of 3.75% of the principal amount
being prepaid; and after the sixth year there is no prepayment fee. The
"treasury rate" is the yield of U.S. Treasury securities with a term equal to
the then-remaining term of the standby loan notes that has become publicly
available on the third business day before the date fixed for repayment. As of
December 31, 2000, the prepayment fee was approximately $24.6 million.

     When the standby loan notes were issued on March 31, 2000, the standby
lenders became entitled to receive 14.4% of our fully diluted new common stock
valued at approximately $24.2 million. The shares were registered with the
Securities and Exchange Commission in connection with the rights offering and
were issued on June 1, 2000. The shares of new common stock issued to the
standby lenders were in addition to the shares of new common stock issued to
holders of the old bonds, to our shareholders prior to reorganization and to
persons participating in the rights offering. Additionally, the standby lenders
received closing fees of approximately $2.5 million as well as expense
reimbursements.

     Operating Plan. We have a high level of indebtedness after the
reorganization. Our total consolidated indebtedness as of December 31, 2000 was
$282.4 million and the ratio of total consolidated indebtedness to total
capitalization was 82%. Due to our high level of indebtedness, our new
management team developed an operating plan for 2000 and 2001 that focuses on
capital projects that we believe will generate increases in:

     o    production;

     o    cash flow from operations; and




                                       35
<PAGE>   36

     o    our proved developed producing crude oil and natural gas reserves and,
          to a lesser extent, total proved reserves.

Management believes that forecasted operating revenues, assuming conservative
growth in production and conservative commodity prices as compared to current
commodity prices, and availability under the new credit facility will be
sufficient to fund the following forecasted expenditures through the end of the
year 2001:

     o    operating expenses, including well repair costs;

     o    general and administrative expenses;

     o    interest due under the bank credit facility;

     o    capital expenditures; and

     o    other current obligations.

Interest owed under the standby loan will be "paid-in-kind" by increasing the
amount of principal outstanding through the issuance of additional standby loan
notes.

     Recapitalization. As mentioned above, we are highly leveraged with a ratio
of total consolidated indebtedness to total capitalization of 82%. Interest due
under our standby loan starts accruing at a 25% rate on April 1, 2001 based on
current crude oil and natural gas prices. Although we currently have adequate
sources of liquidity for the budgeted activities that we expect to conduct in
2001, this high level of indebtedness has several important effects on our
future operations, including:

     o    requiring us to devote a substantial portion of our cash flow from
          operations to pay interest on our indebtedness and not for other uses,
          such as funding working capital or capital expenditures;

     o    limiting our ability to obtain additional financing in the future for
          working capital, capital expenditures, acquisitions, general corporate
          purposes or other purposes thereby restricting our future growth;

     o    putting us at a competitive disadvantage to our competitors who have
          less debt than us; and

     o    limiting our flexibility to plan for, or to react to, changes in our
          business and the oil and gas industry.

We are exploring alternatives to reduce our leverage ratio. Our alternatives
include, but are not limited to:

     o    entering into an equity transaction with another company with a lower
          leverage ratio;

     o    raising additional equity to repay all or a substantial portion of our
          indebtedness outstanding under the standby loan;

     o    converting all or a substantial portion of the standby loan to equity;
          or

     o    combining one or more of these various alternatives.

     Dividends. It is unlikely that we will pay dividends in the foreseeable
future. The terms of the new credit facility and the standby loan restrict our
paying dividends.

     Capital Expenditures. During 2000, we incurred capital expenditures of
$25.3 million compared with $6.3 million for the same period in 1999. We ceased
substantially all of our capital projects in 1999 due to our liquidity problems
and our bankruptcy filing, as discussed above; however, during 2000 we have
increased capital expenditure activities and we expect to continue work on
capital projects. The expenditures incurred during 2000 were largely in
connection with development efforts, including recompletions, workovers and
waterfloods on existing wells throughout the Oklahoma and Mississippi fields. In
addition, during 2000, we drilled 23 wells as follows:




                                       36
<PAGE>   37

     Mississippi Fields:
           Brookhaven          -    1 producing oil; 1 dry hole
           Martinville         -    1 producing oil

     Oklahoma Fields:
           Tatums              -    10 producing oil; 1 service well
           Cox Penn            -    2 producing oil
           East Fitts          -    1 producing oil
           Graham-Deese        -    1 producing gas; 1 dry hole
           Eola                -    1 producing oil; 1 dry hole
           Sholem Alechem      -    1 producing gas
           Non-operated fields -    1 producing gas.

A $40.2 million capital expenditures budget for the year 2001 has been approved
by our board of directors, which will be funded by working capital from
operations and borrowings under the new credit facility. We have no material
capital commitments related to our United States operations and are consequently
able to adjust the level of our expenditures based on available cash flow. No
general and administrative costs associated with our exploration and development
activities were capitalized for 1999 compared with $765,000 of capitalized costs
for 2000.

     Hedging Activities and Other Derivatives. Crude oil and natural gas prices
are subject to significant seasonal, political and other variables which are
beyond our control. In an effort to reduce the effect of the volatility of the
prices received for crude oil and natural gas, we have entered, and expect to
continue to enter, into crude oil and natural gas hedging transactions.
Additionally, our new bank credit facility required us to hedge 75% of our crude
oil production as of March 31, 2000 within ten days of such date for a two-year
period. The bank credit facility also limits our hedging to 85% of crude oil
production. While our hedging program is intended to stabilize cash flow and
thus allow us to plan our capital expenditure program with greater certainty,
any hedging transactions may limit our potential gains if crude oil and natural
gas prices rise substantially over the price established by the hedge. Because
all hedging transactions are tied directly to our crude oil and natural gas
production, we do not believe that these transactions are of a speculative
nature. Gains and losses on these hedging transactions are reflected in crude
oil and natural gas revenues at the time of sale of the hedged production. Any
gain or loss on our crude oil hedging transactions is determined as the
difference between the contract price and the average closing price for West
Texas Intermediate crude oil on the New York Mercantile Exchange for the
contract period. Any gain or loss on our natural gas hedging transactions is
generally determined as the difference between the contract price and the New
York Mercantile Exchange Henry Hub settlement price the next to last business
day of the contract. Consequently, hedging activities do not affect the actual
price received for our crude oil and natural gas. At December 31, 2000, using
the then current price curves, we had $5,078,000 in estimated unrealized losses.

     Based on 2000 production levels, 22% of our 2001 natural gas production,
85% of our 2001 crude oil production and 29% of our 2002 crude oil production
have been hedged as follows:

     Minimum and Maximum Crude Oil Price Arrangements

     o    6,000 barrels per day for the period January 1, 2001 to June 30, 2001,
          with a minimum price of $21.00 and a maximum price of $24.50.

     o    2,000 barrels per day for the period January 1, 2001 to December 31,
          2001, with a minimum price of $26.00 and a maximum price of $30.70.

     o    250 barrels per day for the period January 1, 2001 to June 30, 2001,
          with a minimum price of $20.00 and a maximum price of $22.65.

     o    6,250 barrels per day for the period July 1, 2001 to December 31,
          2001, with a minimum price of $20.00 and a maximum price of $22.80.

     o    500 barrels per day for the period January 1, 2002 to December 31,
          2002, with a minimum price of $22.00 and a maximum price of $28.00.






                                       37
<PAGE>   38

     o    500 barrels per day for the period January 1, 2002 to December 31,
          2002, with a minimum price of $22.00 and a maximum price of $29.60.

     o    500 barrels per day for the period January 1, 2002 to December 31,
          2002, with a minimum price of $24.00 and a maximum price of $28.60.

     Fixed Price Crude Oil Arrangements

     o    5,500 barrels per day for the period January 1, 2002 to March 31, 2002
          with a fixed price of $20.40.

     Minimum and Maximum Natural Gas Price Arrangements

     o    3,000 MMbtus per day for the period January 1, 2001 to May 31, 2001,
          with a minimum price of $3.35 and a maximum price of $4.01.

     We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" effective January 1, 2001. The Statement will require us to
recognize all derivative instruments (including certain derivative instruments
embedded in other contracts) on the balance sheet as either an asset or
liability based on fair value on January 1, 2001. Subsequent changes in fair
value for the effective portion of derivatives qualifying as hedges will be
recognized in other comprehensive income until the hedged item is recognized in
earnings, at which time, changes in fair value previously recognized in other
comprehensive income will be reclassified to earnings. Subsequent changes in
fair value for the ineffective portion of derivatives qualifying as hedges and
for derivatives that are not hedges must be adjusted to fair value through
earnings.

     Our hedge arrangements, as discussed above, qualify as cash flow hedges
under SFAS No. 133. The estimated fair value of these hedge arrangements
represented a net liability of approximately $5.8 million at December 31, 2000,
which will be recorded on the balance sheet effective January 1, 2001, with an
offsetting amount in accumulated other comprehensive loss.

     We have entered into certain lease agreements in Laurel, Mississippi, which
contain provisions for lease payments which are to be calculated based on crude
oil prices. These arrangements are considered to include embedded derivatives
under SFAS No. 133. The estimated fair value of these embedded derivatives
represented a net liability of approximately $300,000 at December 31, 2000,
which will be recorded on the balance sheet effective January 1, 2001, with an
offsetting amount in accumulated effect of an accounting change.

     Our standby loan agreement, as discussed above under "Credit Facilities",
contains an additional semiannual interest feature which is calculated based on
the actual price we receive for our oil and gas production. The additional
interest feature of the standby loan agreement is considered an embedded
derivative under SFAS No. 133. Based on our current fair valuation method, as
discussed below in "Item 7A - Quantitative and Qualitative Disclosure about
Market Risk", adoption of SFAS No. 133 on January 1, 2001 will result in a
decrease in the existing liability at December 31, 2000 of approximately $5.5
million with an offsetting amount to accumulated effect of an accounting change;
however, due to the complexity of this embedded derivative instrument, we are
still evaluating our method of determining fair value.

     Subsequent Event- Discontinuation of Tunisian Operations. We have decided
to discontinue our participation in the exploration of two Tunisia, North Africa
permits due to required capital commitments during 2001 exceeding $7 million net
to our interest, including cash calls currently due totaling $753,000 for
January and February on the Anaguid permit. We own a 45.8% interest in the
Anaguid permit operated by Anadarko Tunisia Anaguid Company and a 12.5% interest
in the Fejaj permit operated by Bligh Tunisia, Inc. We have been actively
marketing our interests in these two permits since emerging from bankruptcy in
March 2000 but have not been successful in selling such interests. We believe it
is in our best interest to preserve our ownership in these permits under the
protection of the bankruptcy court while we attempt to negotiate sales of our
interests in the permits to a third party or parties and to reach settlements
with respect to our obligations under the permits. Therefore, the two
subsidiaries that own these permits, Coho Anaguid, Inc. and Coho International
Limited, filed for protection under Chapter 11 of the United States Bankruptcy
Code on February 20, 2001. We anticipate that the other interest owners in these
Tunisian permits will claim that these two subsidiaries are obligated for their
share of the 2001 capital commitments totaling in excess





                                       38
<PAGE>   39

of $7 million under the terms of the related operating and permit agreements. We
are unable to determine the amount we may ultimately have to pay related to the
2001 capital commitments or the amount we may receive if we are successful in
selling our Tunisia interests. Accordingly, no accrual for the resolution of
these uncertainties has been made at December 31, 2000.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We use financial instruments which inherently have some degree of market
risk. The primary sources of market risk include fluctuations in commodity
prices and interest rate fluctuations.

PRICE FLUCTUATIONS

     Our results of operations are highly dependent upon the prices received for
crude oil and natural gas production. We have entered, and expect to continue to
enter, into forward sale agreements or other arrangements for a portion of our
crude oil and natural gas production to hedge our exposure to price
fluctuations. At December 31, 2000, we have hedged a portion of our crude oil
and natural gas production through December 31, 2002. To calculate the potential
effect of the hedging contracts on our revenues, we applied prices from December
31, 2000 future oil and gas price curves for 2001 and 2002 to the quantity of
our oil and gas production hedged for these periods. In addition, we applied
December 31, 2000 future oil and gas pricing from the price curves assuming a
10% increase in prices and assuming a 10% decrease in prices. The estimated
changes in our revenue through December 31, 2002 resulting from the hedging
contracts are as follows:


<TABLE>
<CAPTION>
                                                                2001             2002
                                                            ------------     ------------
<S>                                                         <C>              <C>
Increase (decrease) based on current price curve            $ (3,785,000)    $ (1,293,000)
Increase (decrease) based on 10% decrease in price curve    $  1,187,000     $    811,000
Increase (decrease) based on 10% increase in price curve    $(10,687,000)    $ (2,665,000)
</TABLE>


     Total debt as of December 31, 2000 included $77.4 million in debt under our
standby loan agreement, which represents the original $72 million standby loan
issued March 31, 2000 and a subsequent loan made on September 29, 2000 of $5.4
million. The standby loan bears interest at a minimum rate of 15% payable
semiannually and after March 31, 2001, additional semiannual interest payments
payable in an amount equal to 1/2% for every $0.25 that the actual price, net of
hedging costs, for our oil and gas production exceeds $15.00 per barrel of oil
equivalent during the applicable semiannual interest period, up to a maximum of
10% additional interest per year. The estimated fair value of the standby loans
at December 31, 2000 of $87.0 million represents the discounted value of total
future estimated payments due under the original standby loan issued on March
31, 2000 and the subsequent loan for payment of paid-in-kind interest issued on
September 29, 2000, using the future crude oil and natural gas price curves at
December 31, 2000. The discount factor for the original standby loan and the
subsequent standby loan of 18.04% and 23.92%, respectively, which were used in
this valuation were determined based on the discount applied at the inception of
each loan. The applied discounts of 18.04% and 23.92% were calculated at each
loan's inception date by using the total future estimated payments due under the
standby loan including additional interest payments estimated over the life of
the standby loan, using the future crude oil and natural price curves at each
loan's inception date as compared to the initial borrowings under the standby
loan and subsequent loan of $72 million and $5.4 million, respectively.

     At each balance sheet date, the future additional interest payments are
calculated using the then current future crude oil and natural gas price curves.
The change in the total future additional interest payments is charged to
interest expense; therefore, changes in crude oil and natural gas prices can
cause a significant change in earnings.

     At December 31, 2000, based on current debt outstanding, we calculated
estimated additional interest payments under the standby loan agreement, using
the December 31, 2000 price curves. These additional interest payments represent
an amount equal to 1/2% for every $0.25 that the actual price received for our
oil and gas production exceeds $15.00 per barrel of oil equivalent up to a
maximum of 10%, as discussed above, beginning April 1, 2001. The estimated
increase in interest expense through December 31, 2001 relating to the
additional interest under the standby loan agreement is $5.8 million using the
December 31, 2000 price curves, which represents the maximum amount of
additional interest under the terms of the standby loan agreement. If the
December 31, 2000 price curves increase or decrease by 10%, the additional
interest accruing on the standby loan would remain at the maximum





                                       39
<PAGE>   40

amount of $5.8 million during 2001. Interest payments under the standby loan
agreement may be paid-in-kind by increasing the amount of principal outstanding
through the issuance of additional standby loan notes, rather than paying the
interest in cash. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources" for
discussion on interest payments to be paid-in-kind.

INTEREST RATE RISK

     Total debt as of December 31, 2000, included $180 million of floating-rate
debt attributed to bank credit facility borrowing. As a result, our annual
interest cost in 2001 will fluctuate based on short-term interest rates. The
impact on annual cash flow of a ten percent change in the floating interest rate
(approximately 98 basis points) would be approximately $1.8 million assuming
outstanding debt of $180 million throughout the year. We have locked in a rate
of 9.75% (6.75% LIBOR plus 3% margin) thru April 9, 2001 on $180 million of bank
credit facility borrowings.




                                       40
<PAGE>   41






ITEM 8. FINANCIAL STATEMENTS


<TABLE>
<S>                                                                                                            <C>
Report of Independent Public Account......................................................................     42

Consolidated Balance Sheets, December 31, 1999 and 2000...................................................     43

Consolidated Statements of Operations, Years Ended December 31, 1998, 1999 and 2000.......................     44

Consolidated Statements of Shareholders' Equity, Years Ended December 31, 1998, 1999 and 2000.............     45

Consolidated Statements of Cash Flows, Years Ended December 31, 1998, 1999 and 2000.......................     46

Notes to Consolidated Financial Statements, Years Ended December 31, 1998, 1999 and 2000..................     47
</TABLE>





                                       41
<PAGE>   42



                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Shareholders of
Coho Energy, Inc.

     We have audited the accompanying consolidated balance sheets of Coho
Energy, Inc. and subsidiaries as of December 31, 1999 and 2000, and the related
consolidated statements of operations, shareholders' equity and cash flows for
each of the three years in the period ended December 31, 2000. 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 in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Coho Energy, Inc. and
subsidiaries as of December 31, 1999 and 2000, and the results of its operations
and cash flows for each of the three years in the period ended December 31, 2000
in conformity with accounting principles generally accepted in the United
States.


                                                Arthur Andersen LLP

Dallas, Texas
March 27, 2001





                                       42
<PAGE>   43



                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

                           CONSOLIDATED BALANCE SHEETS
               (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)

                                     ASSETS
<TABLE>
<CAPTION>
                                                                                      DECEMBER 31
                                                                               -----------------------
                                                                                  1999         2000
                                                                               ---------     ---------
<S>                                                                            <C>           <C>
Current assets
   Cash and cash equivalents ..............................................    $  18,805     $   6,661
   Cash in escrow .........................................................           78         1,042
   Accounts receivable, principally trade .................................       11,158        11,517
   Other current assets ...................................................        1,428           483
                                                                               ---------     ---------
                                                                                  31,469        19,703
Property and equipment, at cost net of accumulated depletion and
   depreciation, based on full cost accounting method (note 3) ............      311,788       317,667
Other assets ..............................................................        5,544        29,421
                                                                               ---------     ---------
                                                                               $ 348,801     $ 366,791
                                                                               =========     =========
                        LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities not subject to compromise:
 Current liabilities
     Accounts payable, principally trade ..................................    $   1,294     $   5,343
     Accrued liabilities and other payables ...............................        2,959         9,773
     Accrued reorganization costs .........................................          792         2,120
     Accrued interest .....................................................       10,175         4,078
     Current portion of long term debt (note 4) ...........................           --         1,036
                                                                               ---------     ---------
          Total current liabilities .......................................       15,220        22,350

Liabilities subject to compromise:
     Accounts payable, principally trade ..................................        4,166            --
     Accrued liabilities and other payables ...............................        5,373            --
     Accrued interest .....................................................       21,379            --
     Accrued state income taxes payable ...................................        4,136            --
     Current portion of long term debt (note 4) ...........................      388,685            --
                                                                               ---------     ---------
          Total liabilities subject to compromise .........................      423,739            --
                                                                               ---------     ---------
                                                                                 438,959        22,350
                                                                               ---------     ---------

Long-term debt, excluding current portion (note 4) ........................           --       282,412
                                                                               ---------     ---------
Commitments and contingencies (note 10) ...................................        1,800           520

Shareholders' equity (note 8)
   Preferred stock, par value $0.01 per share
      Authorized 10,000,000 shares, none issued ...........................           --            --
   Common stock, par value $0.01 per share
      Authorized 50,000,000 shares
      Issued and outstanding 640,088 (restated) and 18,714,175 shares .....          256           187
   Additional paid-in capital .............................................      137,812       324,070
   Retained deficit .......................................................     (230,026)     (262,748)
                                                                               ---------     ---------
           Total shareholders' equity .....................................      (91,958)       61,509
                                                                               ---------     ---------
                                                                               $ 348,801     $ 366,791
                                                                               =========     =========
</TABLE>


           SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



                                       43
<PAGE>   44


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF OPERATIONS
               (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
                                                                                   YEAR ENDED DECEMBER 31
                                                                           ---------------------------------------
                                                                              1998          1999            2000
                                                                           ---------      ---------      ---------
<S>                                                                        <C>            <C>            <C>
Operating revenues
   Net crude oil and natural gas production ..........................     $  68,759      $  57,323      $  90,182
                                                                           ---------      ---------      ---------
Operating expenses
   Crude oil and natural gas production ..............................        23,475         18,218         23,542
   Taxes on oil and gas production ...................................         3,384          2,937          5,778
   General and administrative (note 3) ...............................         7,750          9,905          7,137
   State income tax penalties ........................................            --          1,048             --
   Allowance for bad debt ............................................           894             --            765
   Unsuccessful transaction costs ....................................         2,129             --             --
   Depletion and depreciation ........................................        28,135         13,702         15,316
   Writedown of crude oil and gas properties .........................       188,000          5,433          3,027
                                                                           ---------      ---------      ---------
        Total operating expenses .....................................       253,767         51,243         55,565
                                                                           ---------      ---------      ---------
Operating income (loss) ..............................................      (185,008)         6,080         34,617
                                                                           ---------      ---------      ---------
Other income and expenses
   Interest and other income .........................................           214            246            448
   Interest expense (note 4) .........................................       (32,935)       (33,944)       (36,192)
   Interest expense related to embedded derivative (note 4) ..........           (--)           (--)       (15,163)
                                                                           ---------      ---------      ---------
                                                                              32,721        (33,698)       (50,907)
                                                                           ---------      ---------      ---------
Loss from operations before reorganization costs, income taxes
   and extraordinary items ...........................................      (217,729)       (27,618)       (16,290)
                                                                           ---------      ---------      ---------
Reorganization costs (note 2) ........................................            --          3,123         12,004
                                                                           ---------      ---------      ---------
Loss from operations before income taxes and extraordinary item ......      (217,729)       (30,741)       (28,294)
                                                                           ---------      ---------      ---------
Income taxes (note 6)
   Current (benefit) expense .........................................         4,111            (26)            --
   Deferred (benefit) expense ........................................       (18,494)            --             --
                                                                           ---------      ---------      ---------
                                                                             (14,383)           (26)            --
                                                                           ---------      ---------      ---------
Loss before extraordinary item .......................................      (203,346)       (30,715)       (28,294)
Extraordinary item - loss on extinguishment of indebtedness
   (note 2) ..........................................................            --             --         (4,428)
                                                                           ---------      ---------      ---------
Net loss .............................................................     $(203,346)     $ (30,715)     $ (32,722)
                                                                           =========      =========      =========
Basic and diluted loss per common share (note 1)
   Loss before extraordinary item ....................................     $ (317.68)     $  (47.99)     $   (1.98)
   Extraordinary item ................................................     $      --      $      --      $   (0.31)
   Net loss ..........................................................     $ (317.68)     $  (47.99)     $   (2.29)
</TABLE>


          SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



                                       44
<PAGE>   45


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

                 CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                      (IN THOUSANDS, EXCEPT SHARE AMOUNTS)


<TABLE>
<CAPTION>
                                                     NUMBER OF
                                                      COMMON                           ADDITIONAL       RETAINED
                                                      SHARES            COMMON          PAID-IN         EARNINGS
                                                    OUTSTANDING         STOCK           CAPITAL         (DEFICIT)          TOTAL
                                                    -----------      -----------      -----------      -----------      -----------
<S>                                                  <C>             <C>              <C>              <C>              <C>
Balance at December 31, 1997 ..................      25,603,512      $       256      $   137,812      $     4,035      $   142,103
   Net loss ...................................              --               --               --         (203,346)        (203,346)
                                                    -----------      -----------      -----------      -----------      -----------
Balance at December 31, 1998 ..................      25,603,512              256          137,812         (199,311)         (61,243)
   Net loss ...................................              --               --               --          (30,715)         (30,715)
                                                    -----------      -----------      -----------      -----------      -----------
Balance at December 31, 1999 ..................      25,603,512              256          137,812         (230,026)         (91,958)

Issued on
     (i) Retirement of old common
            shares ............................     (25,603,512)            (256)             256               --               --
     (ii) Issuance of new common
             shares to old common
             shareholders .....................         640,088                6               (6)              --               --
     (iii) Issuance of new common
             shares to extinguish old bond
             debt .............................      15,362,107              154          161,481               --          161,635
     (iv) Issuance of new common
            shares to standby lenders .........       2,694,841               27           24,219               --           24,246
     (v) Issuance of new common
            shares for rights offering ........          17,139               --               --               --               --
     (vi) Stock option compensation ...........              --               --              308               --              308
    Net loss ..................................              --               --               --          (32,722)         (32,722)
                                                    -----------      -----------      -----------      -----------      -----------
 Balance at December 31, 2000 .................      18,714,175      $       187      $   324,070      $  (262,748)     $    61,509
                                                    ===========      ===========      ===========      ===========      ===========
</TABLE>


           SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



                                       45
<PAGE>   46


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31
                                                                           ---------------------------------------
                                                                              1998          1999            2000
                                                                           ---------      ---------      ---------
<S>                                                                        <C>            <C>            <C>
Cash flows from operating activities
   Net loss ..........................................................     $(203,346)     $ (30,715)     $ (32,722)
Adjustments to reconcile net loss to net cash provided
     by operating activities:
   Depletion and depreciation ........................................        28,135         13,702         15,316
   Writedown of crude oil and natural gas properties .................       188,000          5,433          3,027
   Deferred income taxes .............................................       (18,488)            --             --
   Extraordinary item - loss on extinguishment of debt ...............            --             --          4,428
   Standby loan interest .............................................            --             --         10,090
   Standby loan interest related to embedded derivative ..............            --             --         15,163
   Amortization of debt issue costs and other ........................         1,756            679          6,305

Changes in:
   Cash in escrow ....................................................        (1,505)         1,427           (964)
   Accounts receivable ...............................................        (1,150)        (1,194)        (1,622)
   Other assets ......................................................          (628)          (454)           945
   Accounts payable and accrued liabilities ..........................         7,917         25,981        (10,065)
                                                                           ---------      ---------      ---------
Net cash provided by operating activities ............................           691         14,859          9,901
                                                                           ---------      ---------      ---------
Cash flows from investing activities
   Property and equipment ............................................       (70,143)        (6,349)       (25,272)
   Changes in accounts payable and accrued liabilities related to
     exploration and development .....................................        (2,986)        (1,186)         2,685
   Proceeds on sale of property and equipment ........................        61,452             --             --
                                                                           ---------      ---------      ---------
Net cash used in investing activities ................................       (11,677)        (7,535)       (22,587)
                                                                           ---------      ---------      ---------
Cash flows from financing activities
   Increase in long-term debt ........................................        76,113          4,600        255,000
   Debt issuance costs ...............................................            --             --         (9,732)
   Debt extinguishment costs .........................................            --             --         (2,126)
   Repayment of long-term debt .......................................       (62,043)           (20)      (242,600)
                                                                           ---------      ---------      ---------
Net cash provided by financing activities ............................        14,070          4,580            542
                                                                           ---------      ---------      ---------
Net increase (decrease) in cash and cash equivalents .................         3,084         11,904        (12,144)
Cash and cash equivalents at beginning of year .......................         3,817          6,901         18,805
                                                                           ---------      ---------      ---------
Cash and cash equivalents at end of year .............................     $   6,901      $  18,805      $   6,661
                                                                           =========      =========      =========
Cash paid (received) during the period for:
   Interest ..........................................................     $  28,426      $   8,936      $  33,193
   Income taxes ......................................................     $    (256)     $      33      $      --
   Reorganization costs (including prepayments) ......................     $      --      $   3,352      $   7,501
   Reorganization costs (interest income) ............................     $      --      $    (210)     $    (260)
</TABLE>


          SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




                                       46
<PAGE>   47


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000
        (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

    Organization

     Coho Energy, Inc. ("CEI") was incorporated in June 1993 as a Texas
corporation and conducts a majority of its operations through its subsidiary,
Coho Resources, Inc. ("CRI"), and its subsidiaries (collectively the "Company").

    Principles of Presentation

     These consolidated financial statements have been prepared in conformity
with generally accepted accounting principles as presently established in the
United States and include the accounts of CEI as successor to CRI, and its
subsidiaries. All significant intercompany balances and transactions have been
eliminated. Certain reclassifications have been made to the prior year
statements to conform with the current year presentation.

     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 those estimates.

     Substantially all of the Company's exploration, development and production
activities are conducted in the United States and Tunisia jointly with others
and, accordingly, the financial statements reflect only the Company's
proportionate interest in such activities.

    Cash Equivalents

     For purposes of reporting cash flows, cash and cash equivalents include
cash and highly liquid debt instruments purchased with an original maturity of
three months or less.

    Cash in Escrow

     Substantially all of the cash at December 31, 2000 was held in escrow
pursuant to a drilling contract between the Company and a drilling contractor.
Such funds will be disbursed to the drilling contractor upon completion of
services.

    Accounts Receivable

     The Company performs ongoing reviews with respect to the collectibility of
accounts receivable and maintains an allowance for doubtful accounts receivable
($885,000 and $675,000 at December 31, 1999 and 2000, respectively) based on
expected collectibility.

    Crude Oil and Natural Gas Properties

     The Company's crude oil and natural gas producing activities, substantially
all of which are in the United States, are accounted for using the full cost
method of accounting. Accordingly, the Company capitalizes all costs incurred in
connection with the acquisition of crude oil and natural gas properties and with
the exploration for and development of crude oil and natural gas reserves,
including related gathering facilities. Proceeds from disposition of crude oil
and natural gas properties are accounted for as a reduction in capitalized
costs, with no gain or loss recognized unless such dispositions involve a
significant alteration in the depletion rate in which case the gain or loss is
recognized.



                                       47
<PAGE>   48


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     Depletion of crude oil and natural gas properties is provided using the
equivalent unit-of-production method based upon estimates of proved crude oil
and natural gas reserves and production which are converted to a common unit of
measure based upon their relative energy content. Unproved crude oil and natural
gas properties are not amortized, but are individually assessed for impairment.
The costs of any impaired properties are transferred to the balance of crude oil
and natural gas properties being depleted. Estimated future site restoration and
abandonment costs are charged to earnings at the rate of depletion of proved
crude oil and natural gas reserves and are included in accumulated depletion and
depreciation.

     In accordance with the full cost method of accounting, the net capitalized
costs of crude oil and natural gas properties as well as estimated future
development, site restoration and abandonment costs are not to exceed their
related estimated future net revenues discounted at 10%, net of tax
considerations, plus the lower of cost or estimated fair value of unproved
properties.

   Impairment of Long-Lived Assets

     During 1996, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived-Assets To Be Disposed Of." The Company has no long-lived
assets which are subject to the impairment test requirements of SFAS No. 121.
The Company's only long-lived assets are oil and gas properties which are
subject to the full cost ceiling test in accordance with the full cost method of
accounting, as discussed above.

   Other Assets

     Other assets generally include deferred financing charges which are
amortized over the term of the related financing under the straight-line method.
At December 31, 2000, the Company had unamortized deferred financing charges
associated with the new credit facility and standby loan agreement of $5.2
million and $24.1 million, respectively.

   Stock-Based Compensation

     SFAS No. 123, "Accounting for Stock-Based Compensation," encourages, but
does not require, companies to record compensation cost for stock-based employee
compensation plans at fair value. The Company has chosen to continue to apply
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations to account for stock-based compensation.
Accordingly, compensation cost for stock options is measured as the excess, if
any, of the quoted market price of the Company's stock at earliest of the date
of the grant or the first date the exercise price can be determined over the
exercise price an employee must pay to acquire the stock.

   Earnings Per Common Share

     The Company accounts for earnings per share ("EPS") in accordance with SFAS
No. 128, "Earnings Per Share." Under SFAS No. 128, no dilution for any
potentially dilutive securities is included for basic EPS. EPS have been
calculated based on the weighted average number of shares outstanding for the
years ended 1998, 1999 and 2000 of 640,088, 640,088 and 14,266,336,
respectively. Diluted EPS have been calculated based on the weighted average
number of shares outstanding (including common shares plus, when their effect is
dilutive, common stock equivalents consisting of stock options and warrants) for
the years ended 1998, 1999 and 2000 of 640,088, 640,088 and 14,266,336,
respectively. In 1998, 1999 and 2000, conversion of stock options and warrants
would have been antidilutive and, therefore, was not considered in diluted EPS.

     On March 31, 2000, pursuant to the Plan of Reorganization, old shareholders
of the Company's common stock received one share of the Company's new common
stock for each forty shares of the Company's old common stock. All per-share
amounts have been restated based on the new number of shares outstanding
subsequent to the issuance of new shares. See note 2 for further discussion on
the dilution of current equity interests.



                                       48
<PAGE>   49


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


   Income Taxes

     The Company accounts for income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes." Under the asset and liability method of SFAS No.
109, deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
basis. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled.

   Hedging Activities and Other Derivative Instruments

     Periodically, the Company enters into certain arrangements that fix a
minimum and maximum price range in order to fix the price on a portion of its
crude oil and natural gas production. Changes in the market value of crude oil
and natural gas futures contracts are reported as an adjustment to revenues in
the period in which the hedged production is sold. Any gain or loss on our crude
oil hedging transactions is determined as the difference between the contract
price and the average closing price for West Texas Intermediate crude oil on the
New York Mercantile Exchange for the contract period. Any gain or loss on our
natural gas hedging transactions is determined as the difference between the
contract price and the New York Mercantile Exchange Henry Hub settlement price
the next to last business day of the contract period.

     The Company adopted SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" effective January 1, 2001. The Statement will require
the Company to recognize all derivative instruments (including certain
derivative instruments embedded in other contracts) on the balance sheet as
either an asset or liability based on fair value on January 1, 2001. Subsequent
changes in fair value for the effective portion of derivatives qualifying as
hedges will be recognized in other comprehensive income until the hedged item is
recognized in earnings, at which time changes in fair value previously
recognized in other comprehensive income will be reclassified to earnings.
Subsequent changes in fair value for the ineffective portion of derivatives
qualifying as hedges and for derivatives that are not hedges must be adjusted to
fair value through earnings.

     The Company's hedge arrangements, as discussed above, qualify as cash flow
hedges under SFAS No. 133. The estimated fair value of these hedge arrangements
represented a net liability of approximately $5.8 million at December 31, 2000,
which will be recorded on the balance sheet effective January 1, 2001, with an
offsetting amount in accumulated other comprehensive loss.

     The Company has entered into certain lease agreements in Laurel,
Mississippi, which contain provisions for lease payments which are to be
calculated based on crude oil prices. These arrangements are considered to
contain embedded derivatives under SFAS No. 133. The estimated fair value of
these embedded derivatives represented a net liability of approximately $300,000
at December 31, 2000, which will be recorded on the balance sheet, effective
January 1, 2001, with an offsetting amount in accumulated effect of an
accounting change.

     The standby loan agreement, as discussed above under "Credit Facilities",
contains an additional semiannual interest feature which is calculated based on
the actual price the Company receives for its oil and gas production. The
additional interest feature of the standby loan agreement is considered an
embedded derivative under SFAS No. 133. Based on the Company's current fair
valuation method, as discussed further in "Item 7A - Quantitative and
Qualitative Disclosure about Market Risk", adoption of SFAS No. 133 on January
1, 2001 will result in a decrease in the existing liability at December 31, 2000
of approximately $5.5 million, with an offsetting amount to accumulated effect
of an accounting change. However, due to the complexity of this embedded
derivative instrument, the Company is still evaluating its method of determining
fair value.

   Revenue Recognition Policy

     Revenues generally are recorded when products have been delivered and
services have been performed.



                                       49
<PAGE>   50


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


  Environmental Expenditures

     Environmental expenditures that relate to current operations are expensed
or capitalized as appropriate. Expenditures which improve the condition of a
property as compared to the condition when originally constructed or acquired or
prevent environmental contamination are capitalized. Expenditures which relate
to an existing condition caused by past operations, and do not contribute to
future operations, are expensed. The Company accrues remediation costs when
environmental assessments and/or remedial efforts are probable and the cost can
be reasonably estimated.

  Business Segments

     In June 1997, the Financial Accounting Standards Board issued SFAS No. 131,
"Disclosure about Segments of an Enterprise and Related Information", which
requires information to be reported in segments. The Company currently operates
in a single reportable segment; therefore, no additional disclosure is required.

2. REORGANIZATION UNDER BANKRUPTCY PROCEEDINGS

     On August 23, 1999 (the "Petition Date"), the Company and its wholly-owned
subsidiaries, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration,
Inc., Coho Louisiana Production Company and Interstate Natural Gas Company,
filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy
Code (the "Chapter 11 filing") in the U.S. District Court for the Northern
District of Texas (the "Bankruptcy Court"). On November 30, 1999, the Company
filed a plan of reorganization and subsequently filed an amended plan of
reorganization on February 14, 2000 (the "Plan of Reorganization"). On March 20,
2000, the Bankruptcy Court entered an order confirming the Plan of
Reorganization and on March 31, 2000, the Plan of Reorganization was consummated
and the Company emerged from bankruptcy.

     Prior to March 31, 2000, the effective date of the Plan of Reorganization,
the Company had 25,603,512 shares of old common stock issued and outstanding.
Old shareholders received shares representing 4% of new common stock on a basis
of one share of new common stock for 40 shares of old common stock as of the
effective date without giving effect to dilution from shares issued in
connection with the standby loan or shares issued under the rights offering
discussed below. Additionally, shareholders as of February 7, 2000, are eligible
to receive their pro rata share of 20% of any proceeds available from the
lawsuit filed against five affiliates of Hicks, Muse, Tate & Furst (the "Hicks
Muse Lawsuit") after fees and expenses and 40% of any proceeds of the
disposition of the Company's interest in, or the assets of, Coho Anaguid, Inc.
Coho Anaguid owns a 45.83% interest in a permit in Tunisia, North Africa. At
March 31, 2000, the Company charged 40% of the carrying value of Coho Anaguid,
Inc., approximately $1.1 million, to reorganization expense.

     On May 2, 2000, the Company distributed stock rights to the holders of its
old common stock as of the record date of March 6, 2000, to purchase up to an
aggregate of 8,663,846 shares of its new common stock. Each holder of old common
stock received 0.338 rights for every share of old common stock held by such
holder. Each right allowed a holder to buy one share of new common stock at a
price of $10.40 per share. There were 14,669 rights exercised under the
offering; however, pursuant to an antidilution feature which applied to shares
issued in the rights offering, 1.17 shares were issued for each right exercised.
Unexercised rights expired May 31, 2000. The Company received $153,000 upon
completion of the offering on May 31, 2000. Proceeds from the rights offering
were used to pay offering costs; however, offering costs exceeded the proceeds
from the rights offering and the excess costs were charged to accrued
reorganization costs.

     The reorganized value of the Company's assets exceeded the total of all
postpetition liabilities and allowed claims; therefore, the Company did not
qualify for fresh-start accounting. The Company has recorded the following
transactions to effect the Company's Plan of Reorganization consummated on March
31, 2000:

     o    The borrowing of $183.0 million under the Company's new credit
          facility.

     o    The borrowing of $72.0 million under the standby loan and the issuance
          of 2,694,841 shares of new common stock as debt issuance costs at a
          diluted reorganization value of approximately $9.00 per share for a
          total of $24.2 million. The diluted reorganization value of $9.00 per
          share was caused by the old bondholders



                                       50
<PAGE>   51


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


          accepting a dilution in the value of their new common stock to obtain
          the standby loan financing for the reorganized company. The dilution
          is a result of the issuances of additional shares to the standby
          lenders.

     o    Repayment of borrowings outstanding under the old bank credit facility
          together with accrued interest and reasonable fees totaling $260.2
          million, resulting in a $303,000 loss on extinguishment of debt.

     o    Conversion of the old bonds into 15,362,107 shares of new common
          stock, representing 96% of the new common stock without giving effect
          to dilution from shares issued in connection with the standby loan or
          shares issued under the rights offering, at a reorganization value of
          approximately $10.52 per share resulting in a $4.1 million loss on
          extinguishment of debt. Although the old bonds were paid no more than
          in full, the Company did realize a loss on extinguishment of debt
          because the Company's carrying value of the old bonds was less than
          the allowed claim, primarily due to unamortized debt issuance costs.

     o    Provision of $1.6 million to allow for settlement of disputed claims.

     o    Payment of all allowed senior secured claims and all other allowed
          claims less than $1,000, aggregating approximately $500,000.

All other allowed claims will be or have been paid in full as follows:

     o    Substantially all unsecured claims were paid in full in four quarterly
          installments with the final installment made on January 2, 2001.

     o    Priority tax claims will receive five-year, interest-bearing
          promissory notes.

     o    Payment of costs associated with the bankruptcy were paid upon court
          approval during the six months following the consummation of the Plan
          of Reorganization.

     In conjunction with its Plan of Reorganization, the Company terminated 19
corporate office employees and seven officers in April 2000. Costs of $438,000
associated with termination benefits for the 19 corporate office employees were
accrued as of March 31, 2000 and charged to reorganization expense and
subsequently paid in the quarter ended June 30, 2000. Additionally, the Company
rejected all of its officer employment agreements and officer severance
agreements in connection with the Plan of Reorganization, including the seven
terminated officers. The Company has negotiated settlement agreements related to
the claims for these rejected contracts. Approximately $3.0 million was accrued
and charged to reorganization expense for these claims settlements which were
paid during the nine months following the consummation of the Plan of
Reorganization.

     The Company's Plan of Reorganization provided for a retention plan under
which employees were provided with additional incentives to continue their
employment with the Company throughout 2000. The amount of cash awards paid
under the retention plan was $1.2 million, of which 33% was paid upon the
effective date of the Plan of Reorganization and 67% was paid on January 1,
2001. Costs of $419,000 payable upon the effective date of the Plan of
Reorganization were accrued and charged to reorganization expense at March 31,
2000 and subsequently paid on April 14, 2000. Payments of approximately
$815,000, which were paid January 1, 2001, were amortized monthly over the
subsequent nine-month period and charged to reorganization expense.

3. PROPERTY AND EQUIPMENT


<TABLE>
<CAPTION>
                                                                                 December 31
                                                                           ------------------------
                                                                              1999          2000
                                                                           ---------      ---------
<S>                                                                        <C>            <C>
Crude oil and natural gas leases and rights including exploration,
    development and equipment thereon, at cost .......................     $ 684,896      $ 709,118
Accumulated depletion and depreciation ...............................      (373,108)      (391,451)
                                                                           ---------      ---------
                                                                           $ 311,788      $ 317,667
                                                                           =========      =========
</TABLE>

     Overhead expenditures directly associated with exploration for and
development of crude oil and natural gas reserves have been capitalized in
accordance with the accounting policies of the Company. Such charges totaled
$5,749,000, $0, and $765,000 in 1998, 1999 and 2000, respectively. Due to the
cessation of exploration and development of crude oil and natural gas reserves
in 1998, all overhead expenditures during 1999 and the first quarter



                                       51
<PAGE>   52


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


of 2000 were charged to general and administrative expense. Subsequent to the
first quarter of 2000, the Company has increased development work, therefore
related overhead and expenditures were capitalized for the remainder of the
year.

     During 1998, 1999 and 2000, the Company did not capitalize any interest or
other financing charges on funds borrowed to finance unproved properties or
major development projects.

     Unproved crude oil and natural gas properties totaling $56,296,000 and
$30,603,000 at December 31, 1999 and 2000, respectively, have been excluded from
costs subject to depletion. These costs are anticipated to be included in costs
subject to depletion within the next five years.

     Depletion and depreciation expense per equivalent barrel of production was
$4.38, $3.63 and $3.94 in 1998, 1999 and 2000, respectively. During 2000, $25.7
million of unproved costs, previously excluded from the costs subject to
depletion were included in the 2000 costs subject to depletion due to the
reclassification of the related reserves from unproved to proved or abandonment
of the related project.

4. LONG-TERM DEBT


<TABLE>
<CAPTION>
                                                                     December 31
                                                              -------------------------
                                                                 1999           2000
                                                              ---------      ----------
<S>                                                           <C>            <C>
Old bank group loan .....................................     $ 239,600      $      --
Old bonds ...............................................       150,000             --
New credit facility .....................................            --        180,000
Standby loan ............................................            --         77,358
Standby loan interest to be paid-in-kind ................            --          4,732
Standby loan interest related to embedded derivative ....            --         15,163
Promissory notes ........................................            --          5,195
Other ...................................................             3          1,000
                                                              ---------      ---------
                                                                389,603        283,448
Unamortized original issue discount on old bonds ........          (918)            --
Current maturities of long-term debt ....................      (388,685)        (1,036)
                                                              ---------      ---------
                                                              $      --      $ 282,412
                                                              =========      =========
</TABLE>

     The Company and some of its subsidiaries were parties to an old bank group
loan agreement. Borrowings outstanding under the old bank group loan together
with accrued interest and fees totaling $260.2 million were paid on March 31,
2000. The Company obtained the funds necessary for the payment of the old bank
group loan through the combination of borrowings under its new senior revolving
credit facility, borrowings under the standby loan and from cash accumulated
during the bankruptcy.

     Additionally, the Company owed approximately $162 million of principal and
accrued interest under its old bonds. Under the Plan of Reorganization, these
old bonds and accrued interest were converted into 15,362,107 shares of new
common stock.

New Credit Facility

     The new senior revolving credit facility was obtained from a syndicate of
lenders led by The Chase Manhattan Bank, as agent for the new lenders, and has a
principal amount of up to $250 million. The new credit facility limits advances
to the amount of the borrowing base, which is currently at $205 million. The
borrowing base is the loan value assigned to the proved reserves attributable to
the Company's oil and gas properties. The new credit facility is subject to
semiannual borrowing base redeterminations each April 1 and October 1, based on
the Company's reserve reports, and will be made at the sole discretion of the
lenders. The Company or Chase may each request one additional borrowing base
redetermination during any calendar year.



                                       52
<PAGE>   53


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     Interest on advances under the new credit facility will be payable on the
earlier of the expiration of any interest period under the new credit facility
or quarterly. Amounts outstanding under the new credit facility will accrue
interest at the Company's option at either the Eurodollar rate, which is the
annual interest rate equal to the London Interbank Offered Rate for deposits in
United States dollars that is determined by reference to the Telerate Service or
offered to Chase plus an applicable margin (currently 3%), or the prime rate,
which is the floating annual interest rate established by Chase from time to
time as its prime rate of interest plus an applicable margin (currently 2%). All
outstanding advances under the new credit facility are due and payable on March
31, 2003. The new credit facility has been secured by substantially all of the
Company's assets.

The new credit agreement contains financial and other covenants including:

     o    maintenance of required ratios of cash flow to interest expense paid
          or payable in cash (2 to 1 for the average of the last four
          consecutive quarters most recently ended December 31, 2000, gradually
          increasing to 3 to 1 for quarters ending after January 1, 2002),
          senior debt to cash flow required (not to exceed 5 to 1 for the
          average of the last four consecutive quarters ended December 31, 2000,
          gradually decreasing to 3.5 to 1 for any quarter ending after January
          1, 2002), and current assets (including unused borrowing base) to
          current liabilities required (throughout the term of the credit
          agreement, to be 1 to 1 as of the end of each quarter);

     o    restrictions on the payment of dividends; and

     o    limitations on the incurrence of additional indebtedness, the creation
          of liens and the incurrence of capital expenditures.

The lenders received $5.8 million of closing fees in addition to expense
reimbursements.

Standby Loan

     The standby loan was made under a senior subordinated note facility under
which the Company issued $72 million of senior subordinated notes to PPM
America, Inc., Appaloosa Management, L.P., Oaktree Capital Management, L.L.C.,
Pacholder Associates, Inc. and their respective assignees. The Company's rights
and responsibilities and those of the standby lenders are governed by a standby
loan agreement which was executed and delivered on March 31, 2000.

     Debt under the standby loan agreement is evidenced by notes maturing March
31, 2007 and bearing interest at a minimum annual rate of 15% and payable in
cash semiannually. After March 31, 2001, additional semiannual interest payments
will be payable in an amount equal to 1/2% for every $0.25 that the "actual
price" for the Company's oil and gas production exceeds $15 per barrel of oil
equivalent during the applicable semiannual interest period, up to a maximum of
10% additional interest per year. The "actual price" for the Company's oil and
gas production is the weighted average price received by the Company for all its
oil and gas production, including hedged and unhedged production, net of hedging
costs, in dollars per barrel of oil equivalent using a 6:1 conversion ratio for
natural gas. The actual price will be calculated over a six-month measurement
period ending on the date two months before the applicable interest payment
date. Additionally, upon an event of default occurring under the standby loan,
interest will be payable in cash, unless otherwise required to be paid-in-kind,
at a rate equal to 2% per year over the applicable interest rate. Interest
payments under the standby loan may be paid-in-kind subject to the requirements
of the intercreditor arrangement between the standby lenders and the lenders
under the new credit agreement. "Paid-in-kind" refers to the payment of interest
owed under the standby loan by increasing the amount of principal outstanding
through the issuance of additional standby loan notes, rather than paying the
interest in cash. The standby loan semi-annual interest payment was paid-in-kind
when due on September 29, 2000 and has been reflected as an increase in
long-term debt. In addition, accrued interest of $4.7 million at December 31,
2000 has been classified as long-term debt as the March 31, 2001 interest
payment will be paid-in-kind.

     The additional semiannual interest payment feature of the standby loan
agreement based on the actual price received for the Company's oil and gas
production, as discussed above, is considered an embedded derivative instrument.
The additional interest cost associated with this embedded derivative instrument
is calculated at the origination of each loan and at each future balance sheet
date. The aggregate amount of the additional interest payments on the original
$72 million standby loan was estimated at its inception date, using the future
crude oil and natural gas price curves as of such date. These estimated
additional interest payments were added to interest payments



                                       53
<PAGE>   54


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


due based on the minimum annual rate at 15% to determine an effective interest
rate of 18.04% for the term of the original $72 million standby loan. In
addition, the same procedures were applied to the standby loan of $5.4 million
issued on September 29, 2000 to determine an effective rate of 23.92% for the
term of this loan. The aggregate amount of the additional interest payments was
redetermined at December 31, 2000 using the then current future crude oil and
natural gas price curves. The increase of $15.2 million in the aggregate amount
of additional interest payments based on the December 31, 2000 price curves as
compared to the aggregate amount of additional interest payments based on the
price curves at the inception date of each loan was reflected as an increase in
the standby loan debt and a charge to interest expense during 2000. The interest
expense may continue to have significant volatility from period to period based
on changes in future price curves from period to period. For additional
discussion on volatility of interest expense, see note 1 -- "Hedging Activities
and Other Derivative Instruments".

     Payment of the standby loan notes will be expressly subordinate to payments
in full in cash of all obligations arising in connection with the new credit
facility. After the initial 12-month period, cash interest payments may be made
only to the extent by which EBITDA, or earnings before interest, tax,
depreciation and amortization expense, on a trailing four-quarter basis exceeds
$65 million. The new credit agreement also prohibits the Company from making any
cash interest payments on the standby loan indebtedness if the outstanding
indebtedness under both the new credit facility and the standby loan exceeds
3.75 times the EBITDA for the trailing four quarters. The Company does not
currently meet the requirements to make cash interest payments on the standby
loan indebtedness. The Company may prepay the standby loan notes at the face
amount, in whole or in part, in minimum denominations of $1,000,000, plus either
a standard make-whole payment at 300 basis points over the "treasury rate" for
the first four years, or beginning in the fifth year, a prepayment fee of 7.5%
of the principal amount being prepaid; in the sixth year, a prepayment fee of
3.75% of the principal amount being prepaid; and after the sixth year there is
no prepayment fee. The "treasury rate" is the yield of U.S. Treasury securities
with a term equal to the then-remaining term of the standby loan notes that has
become publicly available on the third business day before the date fixed for
repayment.

     When the standby loan notes were issued on March 31, 2000, the standby
lenders became entitled to 14.4% of the Company's fully diluted new common stock
valued at approximately $24.2 million. The shares were registered with the
Securities and Exchange Commission in connection with the rights offering and
were issued on June 1, 2000. The shares of new common stock issued to the
standby lenders were in addition to the shares of new common stock issued to
holders of the old bonds, to the Company's shareholders prior to reorganization
and to persons participating in the rights offering. Additionally, the standby
lenders received closing fees of approximately $2.5 million as well as expense
reimbursements.

Promissory Notes

     Claims for tax, penalty and interest were filed against the Company by the
State of Louisiana and the State of Mississippi. The Company currently has
appeals pending with both taxing authorities for portions of the filed claims.
The Company has accrued an estimated $5.2 million for settlement of these
priority tax claims, of which $4.2 million is included in long term debt and
approximately $1 million is included in current portion of long-term debt.
Five-year, interest-bearing promissory notes will be issued to satisfy these
claims.

Other

     The Company has settled the claims of Chevron Corp. and Chevron USA for
indemnification of environmental liabilities in the Brookhaven field. The terms
of this settlement require the Company to fund $2.5 million over the next two
years to partially finance the implementation of a remediation plan. The Company
paid $1.0 million in June 2000, $500,000 was paid on January 2, 2001 and is
included in current liabilities at December 31, 2000 and the remaining $1.0
million, due on January 1, 2002, is included in long-term debt.



                                       54
<PAGE>   55


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


Debt Repayments

     Based on the balances outstanding under the new credit facility, the
standby loan agreement, the promissory notes, and the Chevron settlement,
estimated aggregate principal repayments for each of the next five years are as
follows: 2001 - $1,052,000, 2002 - $2,036,000, 2003 - $181,036,000, 2004 -
$1,036,000, 2005 - $1,036,000, and $77,357,000 thereafter.

5. SUPPLEMENTAL CASH FLOW INFORMATION

     Supplemental noncash financing activities for the year ended December 31,
2000 are as follows:

<TABLE>
<S>                                                                        <C>
New borrowing:
    Accounts receivable ..............................................     $    (499)
    Debt issuance costs ..............................................        24,245
    Changes in accounts payable and accrued liabilities ..............         5,847
    Long-term debt ...................................................        (5,245)
    Additional paid-in capital .......................................       (24,245)
    Reorganization expense ...........................................          (103)
                                                                           ---------
                                                                           $       0
                                                                           ---------
Extinguishment of debt:
    Debt issuance costs ..............................................     $  (5,231)
    Accrued interest .................................................        15,484
    Current long-term debt ...........................................       149,081
    Issuance of common stock .........................................      (161,636)
    Loss on extinguishment of debt ...................................         4,428
                                                                           ---------
Total cash paid ......................................................     $   2,126
                                                                           ---------

Embedded derivative and standby loan interest:
    Long-term debt ...................................................       (25,253)
    Interest expense .................................................        10,090
    Interest expense related to embedded derivative ..................        15,163
                                                                           ---------
                                                                           $       0
                                                                           =========
</TABLE>

6. INCOME TAXES

     Deferred income taxes are recorded based upon differences between financial
statement and income tax basis of assets and liabilities. The tax effects of
these differences which give rise to deferred income tax assets and liabilities
at December 31, 1999 and 2000, were as follows:

<TABLE>
<CAPTION>
                                                                                     1999           2000
                                                                                   --------      --------
<S>                                                                                <C>           <C>
DEFERRED TAX ASSETS
    Net operating loss carryforwards .........................................     $ 46,614      $ 45,487
    Property and equipment, due to differences in depletion, depreciation,
        amortization and writedowns ..........................................       20,822        13,815
    Alternative minimum tax credit carryforwards .............................        1,466         1,466
    Employee benefits ........................................................           61            25
    Reorganization costs .....................................................        1,062         2,103
    Other ....................................................................          502         6,449
                                                                                   --------      --------
    Total gross deferred tax assets ..........................................       70,527        69,345
    Less valuation allowance .................................................      (70,527)      (69,345)
                                                                                   --------      --------
    Net deferred tax assets ..................................................           --            --
                                                                                   --------      --------
DEFERRED TAX LIABILITIES
    Property and equipment, due to differences in depletion, depreciation,
        amortization and writedowns ..........................................           --            --
                                                                                   --------      --------
NET DEFERRED TAX LIABILITY ...................................................     $     --      $     --
                                                                                   ========      ========
</TABLE>



                                       55
<PAGE>   56


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     The valuation allowance for deferred tax assets as of December 31, 1999 and
2000 includes $248,314 and $192,665, respectively, related to Canadian deferred
tax assets.

     To determine the amount of net deferred tax liability it is assumed no
future capital expenditures will be incurred other than the estimated
expenditures to develop the Company's proved undeveloped reserves.

     The following table reconciles the differences between recorded income tax
expense and the expected income tax expense obtained by applying the basic tax
rate to earnings (loss) before income taxes:

<TABLE>
<CAPTION>
                                                                    1998           1999           2000
                                                                  ---------      ---------      ---------
<S>                                                               <C>            <C>            <C>
Earnings (loss) before income taxes                               $(217,729)     $ (30,742)     $ (32,722)
                                                                  =========      =========      =========
Expected income tax expense (recovery) (statutory rate - 34%)     $ (74,028)     $ (10,452)     $ (11,125)
State taxes - deferred                                               (6,242)          (913)          (611)
Federal benefit of state taxes                                        2,122            310            208
Permanent differences                                                    --            367              9
Expiring NOLs                                                         1,043          2,390         12,724
Change in valuation allowance                                        57,838          8,095         (1,182)
Other                                                                 4,884            177            (23)
                                                                  ---------      ---------      ---------
                                                                  $ (14,383)     $     (26)     $      --
                                                                  =========      =========      =========
</TABLE>

     At December 31, 2000, the Company had the following income tax
carryforwards available to reduce future years' income for tax purposes:

<TABLE>
<CAPTION>
                                                                                    Expires      Amount
                                                                                   ---------    --------
<S>                                                                                <C>          <C>
Net operating loss carryforwards for federal income tax purposes                        2001    $      0
                                                                                        2002           0
                                                                                        2003           0
                                                                                        2004           0
                                                                                   2005-2020     117,949
                                                                                                --------
                                                                                                $117,949
                                                                                                ========

Operating loss carryforwards for Canadian income tax purposes                      2001-2006    $    507
                                                                                                ========
Operating loss carryforwards for federal alternative minimum tax
    purposes                                                                       2009-2020    $101,979
                                                                                                ========
Federal alternative minimum tax credit carryforwards                                      --    $  1,466
                                                                                                ========
Operating loss carryforwards for Mississippi income tax purposes                   2010-2014    $105,743
                                                                                                ========
Operating loss carryforwards for Oklahoma income tax purposes                      2012-2013    $ 50,086
                                                                                                ========
</TABLE>

7. DISPOSITION

     On December 2, 1998, the Company sold its natural gas assets, including its
natural gas properties and the related gas gathering systems, located in Monroe,
Louisiana to an unaffiliated third party for net proceeds of approximately $61.5
million. The proved reserves attributable to such natural gas properties were
approximately 94 billion cubic feet of natural gas and represented approximately
14% of the Company's year-end 1997 proved reserves.

8. SHAREHOLDERS' EQUITY

     To effect the Company's Plan of Reorganization, the Company:

     o    issued new common stock to old shareholders on a basis of one share of
          new common stock for 40 shares of old common stock;



                                       56
<PAGE>   57


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     o    converted the old bonds into 15,362,107 shares of new common stock;

     o    issued 2,694,841 shares of new common stock as debt issuance costs
          under the standby loan agreement; and

     o    issued 17,139 shares of new common stock pursuant to a rights
          offering.

See note 2 for further discussion on the conversion of old common stock and the
issuance of new common stock.

9. STOCK-BASED COMPENSATION

     Prior to the consummation of the Plan of Reorganization, options to
purchase the Company's common stock were granted to officers, directors and key
employees pursuant to the Company's 1993 Stock Option Plan and 1993 Non Employee
Director Stock Option Plan, or assumed from the reorganization of the Company's
subsidiaries in 1993. The stock option plans provided for the issuance of
five-year options with a three-year vesting period and a grant price equal to or
above market value. Some exceptions were made to provide immediate or shortened
vesting periods as approved by the Company's board of directors. All options
outstanding or available for grant prior to the consummation of the Plan of
Reorganization were terminated according to the Plan of Reorganization. Option
shares and values for 1998 and 1999 have not been restated to reflect the
conversion of old common stock to new common stock (see note 2).

     Subsequent to the consummation of the Plan of Reorganization, the Company
has granted options to purchase the Company's common stock to certain officers
and directors of the Company. The options granted to the Company's officers vest
over a two-year period and the options granted to the Company's directors are
immediately vested on the grant date.

     A summary of the status of the Company's stock option plans at December 31,
1998, 1999 and 2000 and changes during the years then ended follows:


<TABLE>
<CAPTION>

                                        1998                      1999                       2000
                               ----------------------    ----------------------    -----------------------
                                             WTD AVG                   WTD AVG                    WTD AVG
                                 SHARES      EX PRICE      SHARES      EX PRICE      SHARES       EX PRICE
                               ----------    --------    ----------    --------    ----------     --------
<S>                             <C>            <C>        <C>            <C>        <C>             <C>
Outstanding at January 1        2,823,815      $6.96      2,631,260      $6.98      2,238,101       7.13
    Granted                        14,000       6.88             --         --      1,031,448       8.10
    Exercised                          --         --             --         --             --         --
    Canceled                      (75,000)      8.90        (30,000)      8.42     (2,238,101)      7.13
    Expired                      (131,555)      5.40       (363,159)      5.97             --         --
                               ----------      -----     ----------      -----     ----------      -----
Outstanding at December 31      2,631,260       6.98      2,238,101       7.13      1,031,448       8.10
                               ----------      -----     ----------      -----     ----------      -----
Exercisable at December 31      2,310,438       6.60      2,112,445       6.94        295,362       7.88

Available for grant at
    December 31                   189,919                   437,668                         0
</TABLE>

     Significant option groups outstanding at December 31, 2000 and related
weighted average price and life information follows:

<TABLE>
<CAPTION>
                         Options          Options         Wtd Avg          Remaining
Grant Date             Outstanding      Exercisable    Exercise Price     Life (Years)
----------             -----------      -----------    --------------     ------------
<S>                      <C>              <C>              <C>                <C>
April 1, 2000            981,448          245,362          $ 8.19             (a)

August 17, 2000           50,000           50,000          $6.375             (a)
</TABLE>

(a)  Options expire one year after termination of participant.



                                       57
<PAGE>   58


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     The weighted average fair value of options at the date of grant for options
granted during 1998 and 2000 was $3.12 and $4.42 per option, respectively. The
fair value of options at date of grant was estimated using the Black-Scholes
model with the following weighted average assumptions:

<TABLE>
<CAPTION>
                              1998           1999        2000
                            -------         ------      ------
<S>                          <C>              <C>       <C>
Expected life (years)            5            --            5
Interest rate                 5.67%           --        6.305%
Volatility                   42.01%           --        42.00%
Dividend yield                  --            --           --
</TABLE>

     Had compensation cost for these plans been determined consistent with SFAS
No. 123, "Accounting for Stock-Based Compensation", the Company's pro forma net
income and earnings per share from continuing operations would have been as
follows:

<TABLE>
<CAPTION>
                                                                         1998(c)    1999 (c)      2000
                                                                       ----------   --------    --------
<S>                                                                    <C>          <C>         <C>
Net loss                     As reported .......................       $ (203,346)  $(30,715)   $(32,722)
                             Pro forma .........................       $ (204,108)  $(31,321)   $(34,281)
Basic loss per share         As reported .......................       $  (317.68)  $ (47.99)   $  (2.29)
                             Pro forma .........................       $  (318.88)  $ (48.93)   $  (2.40)
Diluted loss per share       As reported .......................       $  (317.68)  $ (47.99)   $  (2.29)
                             Pro forma .........................       $  (318.88)  $ (48.93)   $  (2.40)
</TABLE>

(c) Per share amounts restated for conversion of old common stock to new common
stock (see note 2)

10. COMMITMENTS AND CONTINGENCIES

(a)  Like other crude oil and natural gas producers, the Company's operations
     are subject to extensive and rapidly changing federal and state
     environmental regulations governing emissions into the atmosphere, waste
     water discharges and solid and hazardous waste management activities. At
     December 31, 2000, the Company has accrued approximately $584,000 related
     to such costs, of which $64,000 is included in current liabilities and
     $520,000 is included in contingent liabilities. At this time, the Company
     does not believe that any potential liability, in excess of amounts already
     provided for, would have a significant effect on the Company's financial
     position or the results of operations.

(b)  The Company's operations are subject to site restoration and abandonment
     costs. The Company's policy is to make a provision for future site
     restoration charges on a unit-of-production basis. Total future site
     restoration costs are estimated to be $6,000,000. A total of $3.1 million
     has been included in depletion and depreciation expense with respect to
     such costs as of December 31, 2000.

(c)  On May 27, 1999, the Company filed a lawsuit against five affiliates of
     Hicks, Muse, Tate & Furst. The lawsuit alleges (1) breach of the written
     contract terminated by HM4 Coho L.P. ("HM4"), a limited partnership formed
     by Hicks Muse on behalf of the Hicks, Muse, Tate & Furst Equity Fund IV, in
     December 1998, (2) breach of the oral agreements reached with HM4 on the
     restructured transaction in February 1999 and (3) promissory estoppel. In
     the lawsuit, the Company seeks monetary damages of approximately $300
     million. Discovery is substantially complete and both sides have filed
     motions for summary judgement, which were heard during January 2001. The
     Court has denied the Company's motion for summary judgment, and has
     granted, in part, and denied, in part, Hicks, Muse's motion. Based on these
     orders, it appears that the Company will be able to go to trial on a claim
     for breach of contract that has an actual damages of up to $165 million.
     The Company believes that the lawsuit has merit and that the actions of HM4
     in December 1998 and February 1999 were the primary cause of the Company's
     liquidity crisis; however, there can be no assurance as to the outcome of
     this litigation.

(d)  On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of
     Hicks, Muse, Tate & Furst, filed a lawsuit against certain former officers
     of the Company alleging, among other things, such officers made or caused
     to be made false and misleading statements as to the proved oil and gas
     reserves purportedly owned by the Company. The plaintiffs are asking for
     compensatory damages of approximately $15 million plus punitive damages.



                                       58
<PAGE>   59


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     Pursuant to the Company's bylaws, the Company may be required to indemnify
     such former officers against damages incurred by them as a result of the
     lawsuit not otherwise covered by the Company's directors' and officers'
     liability insurance policy. The judge has dismissed certain claims and the
     case is set for trial in the spring of 2002. The Company believes the
     lawsuit is without merit and does not expect the outcome of the lawsuit to
     have a material adverse effect on the Company's financial position or
     results of operations.

(e)  During June 1999, the Company extended its Anaguid permit in Tunisia, North
     Africa through December 2001. The Company has a commitment to drill two
     additional wells during this two-year period. See note 15 -- "Subsequent
     Events" for further discussion regarding the Company's operations in
     Tunisia, North Africa.

(f)  The Company has leased (i) 26,751 square feet of office space in Dallas,
     Texas under a non-cancellable lease extending through December 2005, with a
     one time cancellation option during September 2003, (ii) 10,000 square feet
     of office space in Ratliff City, Oklahoma and (iii) surface leases in
     Laurel, Mississippi with expiration dates extending through the year 2018.
     Rental expense totaled $1,668,000, $1,798,000 and $1,394,000 in 1998, 1999
     and 2000, respectively. Minimum rentals payable under these leases for each
     of the next five years are as follows: 2001 - $1,192,000; 2002 -
     $1,192,000; 2003 - $1,173,000; 2004 - $1,172,000 and 2005 -$1,172,000.
     Total rentals payable over the remaining terms of the leases are
     $4,180,000.

(g)  The Company has entered into employment agreements with certain of its
     officers. In addition to base salary and participation in employee benefit
     plans offered by the Company, these employment agreements generally provide
     for a severance payment in an amount equal to two times the rate of base
     annual compensation of the officer in the event there is a change of
     control or in the event the officer's employment is terminated for other
     than cause.

     The officers' aggregate annual compensation covered under such employment
     agreements is approximately $800,000.

(h)  The Company has entered into executive stay agreements with certain key
     employees which are designed to encourage these key employees to continue
     to carry out their duties with the Company in the event of a change in
     control of the Company. If the employee, subsequent to a change in control,
     continues to be employed by the Company for a period of not less than 180
     days or if the employee's employment is terminated for other than cause,
     these stay agreements generally provide for a payment in an amount equal to
     1.0 times the employees annual salary.

     The annual salary paid to the key employees covered under such severance
     agreements aggregates approximately $406,000.

11. FINANCIAL INSTRUMENTS AND CREDIT RISK CONCENTRATIONS

     Financial instruments which are potentially subject to concentrations of
credit risk consist principally of cash, cash equivalents and accounts
receivable. Cash and cash equivalents are placed with high credit quality
financial institutions to minimize risk. The carrying amounts of these
instruments approximate fair value because of their short maturities. The
Company has entered into certain financial arrangements which act as a hedge
against price fluctuations in future crude oil and natural gas production.
Included in operating revenues are gains (losses) of $488,000, $0 and
$(10,401,000) for 1998, 1999 and 2000, respectively, resulting from these
hedging programs. At December 31, 1999 and 2000, the Company had no deferred
hedging gains or losses. As of December 31, 2000, the Company had $5,078,000 in
unrealized losses. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Results of Operations" for discussion on
hedging arrangements.

     Fair values of the Company's financial instruments are estimated through a
combination of management's estimates and by reference to quoted prices from
market sources and financial institutions, if available. As of December 31,
2000, the fair market value of the Company's standby loan notes was $87.0
million compared to the related carrying value of $92.5 million. The fair value
of the old bonds at December 31, 1999 was $83 million compared to the related
carrying value of $149 million. The carrying value of the new credit facility
and old bank group loan agreement approximated fair market value at December 31,
2000 and December 31, 1999 since the applicable interest rate approximated the
market rate.



                                       59
<PAGE>   60


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     During 1998, three purchasers of our crude oil and natural gas, EOTT Energy
Corp. ("EOTT"), Amoco Production Company, and Mid Louisiana Marketing Company,
accounted for 42%, 28% and 14%, respectively, of the Company's revenue. During
1999, EOTT and Amoco Production Company accounted for 39% and 41%, respectively,
of the Company's revenue. During 2000, EOTT and Amoco Production Company
accounted for 41% and 29%, respectively, of the Company's revenue. Included in
accounts receivable is $1,965,000 and $114,000 and $250,000 from these customers
at December 31, 1998, 1999 and 2000, respectively. In October 2000, we began
selling our crude oil that had been previously sold to Amoco, to Teppco Crude
Oil, LLP and Sunoco, Inc.

12. RELATED PARTY TRANSACTIONS

     (a) In 1990, the Company made a non-interest bearing loan in the amount of
$205,000 to Jeffrey Clarke, the Company's former President and Chief Executive
Officer, to assist him in the purchase of a house in Dallas. The Company has
entered into an executive employment severance agreement with Mr. Clarke in
which he will receive a forbearance of the loan from the Company in exchange for
his assistance in the Hicks Muse lawsuit. The loan will be forgiven on the date
the Hicks Muse lawsuit is settled or otherwise completed. At March 31, 2000, the
Company provided an allowance for this loan and charged reorganization expense.

     (b) Pursuant to an equity offering, the Company's officers and directors
were precluded from selling stock for a 90-day period beginning October 3, 1997
(the "Lock Up Period"). On October 6, 1997, the Company made sole recourse,
non-interest bearing loans of $622,111, payable on demand, secured by the
related Company's common stock to certain officers and a director. The loans
were made to provide assistance in acquiring stock upon exercise of expiring
stock options during the Lock Up Period. During 1998, the Company provided an
allowance for bad debt for the entire amount of such loans due to the decrease
in the share price of the Company's common stock provided by such officers and
directors as collateral. The Company released these parties from any claim under
these loans in connection with the cancellation of contracts and the related
settlement negotiations in the Plan of Reorganization.

     (c) Under the terms of a Financial Advisory Agreement entered into between
the Company and Hicks, Muse & Co. Partners, L.P. ("HMCo"), on August 21, 1998,
the Company paid HMCo $1,250,000 as compensation for HMCo's services as a
financial advisor to the Company and its subsidiaries in connection with an
agreement to issue common stock of the Company to HM4. John R. Muse and Lawrence
D. Stuart, Jr., are each limited partners in HMCo and limited partners of a
limited partner in HM4, and at the time of the payment to HMCo, were directors
of the Company under an agreement with Energy Investment Partnership No. 1, L.P.
On March 18, 1999, Messrs, Muse and Stuart resigned from the board of directors
of the Company.

     (d) On March 31, 2000, the Company issued $72 million of senior
subordinated notes (see note 4), of which $65.5 million were issued to the
Company's major shareholders and their affiliates. In addition, participants
purchasing the notes were entitled to a cash origination fee equal to 3 1/2% of
the face amount of the notes purchased plus 2,694,841 shares of the Company's
common stock. Share information, loan origination fees and notes purchased by
the Company's major shareholders are as follows:

<TABLE>
<CAPTION>
                                                                 Loan Origination     Senior Notes
                                                  Common Shares   Fee (in 000's)   Purchased (in 000's)
                                                  -------------  ----------------  --------------------
<S>                                                 <C>             <C>                <C>
PPM America, Inc. and affiliates ............       1,466,723       $   1,382          $  39,500
Appaloosa Management, L.P. and affiliates ...         587,157       $     560          $  16,000
Oaktree Capital Management, LLC and
  affiliates ................................         374,283       $     350          $  10,000
</TABLE>

In addition, during April 2000, certain officers of the Company were entitled,
pursuant to their employment contracts, to participate in the senior note loans
and receive the benefit of the loan origination fee and additional shares of
common stock issued by purchasing senior notes at face value from Appaloosa
Management, L.P. and PPM America, Inc. and affiliates. Share information, loan
origination fees and senior notes purchased from the major shareholders by
officers of the Company are as follows:



                                       60
<PAGE>   61


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


<TABLE>
<CAPTION>
                                              Loan Origination     Senior Notes
                             Common Shares     Fee (in 000's)   Purchased (in 000's)
                             -------------    ----------------  --------------------
<S>                             <C>                <C>                <C>
Michael McGovern ........       13,100             $12.5              $  350
Gary L. Pittman .........        6,550             $ 6.0              $  175
Gerald E. Ruley .........        3,743             $ 3.5              $  100
</TABLE>

     (e) The senior subordinated notes, as discussed in (d) above, require
semiannual interest payments payable in cash or, if required pursuant to the
intercreditor arrangement between the standby lenders and the lenders under the
new credit agreement, paid-in-kind (see note 4). On September 29, 2000, the
semiannual interest payment of $5,358,000 was paid-in-kind to the holders of the
senior subordinated notes, resulting in the issuance of new senior subordinated
notes to certain major shareholders and officers as follows:

<TABLE>
<CAPTION>
                                                Senior Notes Issued (in 000's)
                                                ------------------------------
<S>                                                         <C>
PPM America, Inc. and affiliates ............               $2,923
Appaloosa Management, L.P. and affiliates ...               $1,170
Oaktree Capital Management, LLC and
  affiliates ................................               $  657
Michael McGovern ............................               $   26
Gary L. Pittman .............................               $   13
Gerald E. Ruley .............................               $    7
</TABLE>

     (f) On April 1, 2000, the Company entered into an agreement with Pirinate
Consulting Group, LLC with respect to monthly financial advisory services to be
performed by Eugene Davis for the Company for a monthly retainer of $15,000. Mr.
Davis is Chairman and Chief Executive Officer of Pirinate Consulting Group, LLC
and is currently a director of the Company.

13. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
                                                      First            Second           Third           Fourth            Total
                                                    ---------        ---------        ---------        ---------        ---------
<S>                                                 <C>              <C>              <C>              <C>              <C>
2000
   Operating revenues .......................       $  22,646        $  23,858        $  21,947        $  21,731        $  90,182
   Operating income (loss) ..................           9,360           11,429            8,864            4,964           34,617
   Net income (loss) ........................         (14,629)          (2,315)         (23,039)           7,261          (32,722)
   Basic income (loss) per share ............       $  (17.45)       $    (.12)       $   (1.23)       $     .39        $   (2.29)
   Diluted income (loss) per share ..........       $  (17.45)       $    (.12)       $   (1.23)       $     .39        $   (2.29)

1999
   Operating revenues .......................       $   8,967        $  12,161        $  16,829        $  19,366        $  57,323
   Operating income (loss) ..................          (1,127)             428             (675)           7,454            6,080
   Net loss .................................          (8,987)         (10,102)         (10,733)            (893)         (30,715)
   Basic loss per share (restated) ..........       $  (14.04)       $  (15.78)       $  (16.77)       $   (1.40)       $  (47.99)
   Diluted loss per share (restated) ........       $  (14.04)       $  (15.78)       $  (16.77)       $   (1.40)       $  (47.99)

1998
   Operating revenues .......................       $  21,143        $  18,147        $  16,539        $  12,930        $  68,759
   Operating income (loss) ..................         (28,206)         (38,306)           1,344         (119,840)        (185,008)
   Net loss .................................         (22,301)         (41,611)          (7,168)        (132,266)        (203,346)
   Basic loss per share (restated) ..........       $  (34.84)       $  (65.01)       $  (11.20)       $ (206.64)       $ (317.68)
   Diluted loss per share (restated) ........       $  (34.84)       $  (65.01)       $  (11.20)       $ (206.64)       $ (317.68)
</TABLE>

     Basic per share figures are computed based on the weighted average number
of shares outstanding for each period shown. Diluted per share figures are
computed based on the weighted average number of shares outstanding including
common stock equivalents, consisting of stock options and warrants, when their
effect is dilutive. 1998, 1999 and the first quarter of 2000 have been restated
to reflect the conversion of old common stock to new common stock.



                                       61
<PAGE>   62


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


14. SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS ACTIVITIES

     Costs Incurred

        Costs incurred for property acquisition, exploration and development
activities were as follows:

<TABLE>
<CAPTION>
                                                                 1998           1999           2000
                                                               --------       --------       --------
<S>                                                            <C>            <C>            <C>
Property acquisitions
    Proved .............................................       $  8,432       $     --       $    432
    Unproved ...........................................          4,646             --             --
Exploration ............................................          5,061          2,198          2,330
Development ............................................         51,049          4,101         22,415
Other ..................................................            955             50             96
                                                               --------       --------       --------
                                                               $ 70,143       $  6,349       $ 25,273
                                                               ========       ========       ========
Property and equipment, net of accumulated depletion ...       $324,574       $311,788       $317,734
                                                               ========       ========       ========
</TABLE>

     Quantities of Oil and Gas Reserves (Unaudited)

     The following table presents estimates of the Company's proved reserves,
all of which have been prepared by the Company's engineers and evaluated by
independent petroleum consultants. See "Business and Properties -- Reserves" for
discussion on decrease in estimated reserves. Substantially all of the Company's
crude oil and natural gas activities are conducted in the United States.

<TABLE>
<CAPTION>
                                                              Reserve Quantities
                                                           ------------------------
                                                              Oil            Gas
                                                            (MBbls)         (MMcf)
                                                           --------        --------
<S>                                                         <C>             <C>
Estimated reserves at December 31, 1997 ............         95,084         147,505
Revisions of previous estimates ....................         (7,645)          4,459
Purchase of reserves in place ......................          6,842             480
Sales of reserves in place .........................             --         (94,106)
Extensions and discoveries .........................         10,792          16,114
Production .........................................         (5,069          (8,124)
                                                           --------        --------
Estimated reserves at December 31, 1998 ............        100,004          66,328
Revisions of previous estimates ....................          9,718         (25,257)
Purchase of reserves in place ......................             --              --
Sales of reserves in place .........................             --              --
Extensions and discoveries .........................            734           2,175
Production .........................................         (3,343)          2,608)
                                                           --------        --------
Estimated reserves at December 31, 1999 ............        107,113          40,638
Revisions of previous estimates ....................         (9,239)        (11,083)
Purchase of reserves in place ......................            285              --
Sales of reserves in place .........................             (9)            (26)
Extensions and discoveries .........................          1,377           1,258
Production .........................................         (3,534)         (2,076)
                                                           --------        --------
Estimated reserves at December 31, 2000 ............         95,993          28,711
                                                           ========        ========
Proved developed reserves at December 31,
   1998 ............................................         66,869          48,176
   1999 ............................................         73,748          25,794
   2000 ............................................         65,832          24,453
</TABLE>



                                       62
<PAGE>   63


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     Standardized Measure of Oil and Gas Reserves (unaudited)

     Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Reserves.

     The following standardized measure of discounted future net cash flows was
computed in accordance with the rules and regulations of the Securities and
Exchange Commission and SFAS No. 69 using year end prices and costs, and year
end statutory tax rates. Royalty deductions were based on laws, regulations and
contracts existing at the end of each period. No values are given to unproved
properties or to probable reserves that may be recovered from proved properties.

     The inexactness associated with estimating reserve quantities, future
production and revenue streams and future development and production
expenditures, together with the assumptions applied in valuing future
production, substantially diminishes the reliability of this data. The values so
derived are not considered to be an estimate of fair market value. The Company
therefore cautions against this use.

     The following tabulation reflects the Company's estimated discounted future
cash flows from crude oil and natural gas production:

<TABLE>
<CAPTION>
                                                                         1998              1999                2000
                                                                     -----------        -----------        -----------
<S>                                                                  <C>                <C>                  <C>
Future cash inflows ..........................................       $ 1,081,003        $ 2,562,981          2,597,866
Future production costs ......................................          (419,820)          (642,024)          (760,223)
Future development costs .....................................          (112,165)          (136,589)          (123,636)
Future income taxes ..........................................           (55,008)          (435,311)          (419,290)
                                                                     -----------        -----------        -----------
Future net cash flows ........................................           494,010          1,349,057          1,294,717
Annual discount at 10% .......................................          (224,712)          (656,182)          (698,428)
                                                                     -----------        -----------        -----------
Standardized measure of discounted future net cash flows .....       $   269,298        $   692,875        $   596,289
                                                                     ===========        ===========        ===========
Crude oil posted reference price ($ per Bbl) (a) .............       $     12.05        $     25.60        $     26.80
Estimated December 31 Company average realized price
   $/Bbl .....................................................       $      9.36        $     21.78        $     23.72
   $/Mcf (b) .................................................       $      2.10        $      2.25        $     11.18
</TABLE>

(a)  1998 price was based on year end West Texas Intermediate posted prices and
     1999 and 2000 were based on year end NYMEX prices.

(b)  1998 and 1999 prices were based on year end posted prices under our gas
     contracts. 2000 price was based on the year end NYMEX price of $9.78 per
     MMBTU.



                                       63
<PAGE>   64


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     The following are the significant sources of changes in discounted future
net cash flows relating to proved reserves:

<TABLE>
<CAPTION>
                                                                        1998             1999             2000
                                                                     ---------        ---------        ---------
<S>                                                                  <C>              <C>              <C>
Crude oil and natural gas sales, net of production costs .....       $ (41,412)       $ (36,168)       $ (60,862)
Net changes in anticipated prices and production costs .......        (184,445)         582,297           65,129
Extensions and discoveries, less related costs ...............          39,510            7,683           24,387
Changes in estimated future development costs ................            (905)         (19,335)           1,048
Development costs incurred during the period .................          22,040            2,212           11,703
Net change due to sales and purchase of reserves in place ....         (53,534)              --            1,616
Accretion of discount ........................................          52,628           26,930           79,015
Revision of previous quantity estimates ......................         (20,178)          45,605          (90,700)
Net changes in income taxes ..................................          58,084          (97,279)         (63,033)
Changes in timing of production and other ....................         (70,683)         (88,368)         (64,889)
                                                                     ---------        ---------        ---------

Net increase (decrease) ......................................        (198,895)         423,577          (96,586)
Beginning of year ............................................         468,193          269,298          692,875
                                                                     ---------        ---------        ---------
Standardized measure of discounted future net cash flows .....       $ 269,298        $ 692,875        $ 596,289
                                                                     =========        =========        =========
</TABLE>

15. SUBSEQUENT EVENTS

     Tunisian Operations. The Company decided to discontinue its participation
in the exploration of two Tunisia, North Africa permits due to capital
commitments during 2001 exceeding $7 million net to our interest, including cash
calls currently due totaling $753,000 for January and February on the Anaguid
permit. The Company owns a 45.8% interest in the Anaguid permit operated by
Anadarko Tunisia Anaguid Company and a 12.5% interest in the Fejaj permit
operated by Bligh Tunisia, Inc. The Company has been actively marketing its
interests in these two permits since emerging from bankruptcy in March 2000 but
has not been successful in selling such interests. The Company believes it is in
its best interest to preserve its ownership in these permits under the
protection of the bankruptcy court while it tries to negotiate sales of its
interests in the permits to a third party or parties and to reach settlements
with respect to its obligations under the permits. Therefore, the two
subsidiaries that own these permits, Coho Anaguid, Inc. and Coho International
Limited, filed for protection under Chapter 11 of the United States Bankruptcy
Code on February 20, 2001. As a result, the Company took a writedown of $3.0
million during the fourth quarter of 2000. The Company anticipates that the
other interest owners in these Tunisian permits will claim that these two
subsidiaries are obligated for their share of the 2001 capital commitments
totaling in excess of $7 million under the terms of the related operating and
permit agreements. The Company is unable to determine the amount it may
ultimately have to pay related to the 2001 capital commitments or the amount it
may receive if it is successful in selling its Tunisian interests. Accordingly,
no accrual for the resolution of these uncertainties has been made at December
31, 2000.

     The Chapter 11 filing included Coho Anaguid, Inc. and Coho International
Limited. The following information summarizes the combined results of operations
for these subsidiaries. This information has been prepared on the same basis as
the consolidated financial statements.

<TABLE>
<CAPTION>
                                                                 Year Ended
                                                             December 31, 2000
                                                             -----------------
<S>                                                          <C>
Current assets ............................................      $      9
                                                                 --------
  Total assets ............................................      $      9
                                                                 ========

Current liabilities .......................................      $    625
Accounts payable to affiliates ............................         9,601
Shareholder's equity ......................................       (10,217)
                                                                 --------
                                                                 $      9
                                                                 ========

Operating expenses ........................................      $  4,283
Net loss ..................................................      $  4,283
</TABLE>



                                       64
<PAGE>   65


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

     None









                                       65
<PAGE>   66


                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The information required by this item appears in the Company's proxy
statement for the Annual Meeting of Shareholders to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A, which information is
incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

     The information required by this item appears under the caption "Executive
Compensation" set forth in the Company's proxy statement for the Annual Meeting
of Shareholders to be filed with the Securities and Exchange Commission pursuant
to Regulation 14A, which information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The information required by this item appears under the caption "Security
Ownership of Certain Beneficial Owners and Management" set forth in the
Company's proxy statement for the Annual Meeting of Shareholders to be filed
with the Securities Commission pursuant to Regulation 14A, which information is
incorporated herein by references.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information required by this item appears under the caption "Certain
Relationships and Related Transactions" set forth in the Company's proxy
statement for the Annual Meeting of Shareholders to be filed with the Securities
and Exchange Commission pursuant to Regulation 14A, which information is
incorporated herein by reference.







                                       66
<PAGE>   67


                                     PART IV


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

     (a) Documents Filed as a Part of this Report

1.   FINANCIAL STATEMENTS

     Reference is made to the Index to Financial Statements under Item 8 on page
41.

2.   FINANCIAL STATEMENT SCHEDULES

     All schedules and financial statements are omitted because they are not
applicable or the required information is shown in the financial statements or
notes thereto listed above in Item 14(a) 1.

3.   EXHIBITS

<TABLE>
<CAPTION>
     EXHIBIT
     NUMBER                             DESCRIPTION
     ------                             -----------
<S>               <C>
         2.1 -    Company's First Amended and Restated Chapter 11 Plan of
                  Reorganization as filed with the United States Bankruptcy
                  Court for the Northern District of Texas on February 14, 2000
                  (incorporated by reference to Exhibit 2.1 to the Company's
                  Registration Statement on Form S-1 (Registration Number
                  333-96331)).

         2.2 -    First Amended and Restated Disclosure Statement with respect
                  to the Joint Plan of Reorganization under Chapter 11 of the
                  United States Bankruptcy Code as filed with the United States
                  Bankruptcy Court for the Northern District of Texas on
                  February 14, 2000 (incorporated by reference to Exhibit 2.2 to
                  the Company's Registration Statement on Form S-1 (Registration
                  Number 333-96331)).

         2.3 -    Findings of Fact, Conclusions of Law, and Order Confirming
                  Debtors' First Amended and Restated Chapter 11 Plan of
                  Reorganization as filed with the United States Bankruptcy
                  Court for the Northern District of Texas on March 20, 2000
                  (incorporated by reference to the Company's Registration
                  Statement on Form S-1 (Registration Number 333-96331).

         3.1 -    Form of Amended and Restated Articles of Incorporation of
                  the Company (incorporated by reference to the Company's
                  Registration Statement on Form S-1 (Registration Number
                  333-96331)).

         3.2 -    Form of Amended and Restated Bylaws of the Company
                  (incorporated by reference to the Company's Registration
                  Statement on Form S-1 (Registration Number 333-96331)).

         4.1 -    Form of Amended and Restated Articles of Incorporation
                  (included as Exhibit 3.1 above).

         4.2 -    Form of Amended and Restated Bylaws of the Company (included
                  as Exhibit 3.2 above).

        10.1 -    Credit Agreement dated as of March 31, 2000, among Coho
                  Energy, Inc., The Chase Manhattan Bank, Meespierson Capital
                  Corp., Fleet National Bank, Credit Lyonnais, New York Branch,
                  ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC
                  Inc., Credit Agricole Indosuez, and Natexis Banque BFCE
                  (incorporated by reference to the Company's Registration
                  Statement on Form S-1 (Registration Number 333-96331)).

        10.2 -    First Amendment to Credit Agreement dated November 27, 2000
                  among Coho Energy, Inc., The Chase Manhattan Bank, Meespierson
                  Capital Corp., Fleet National Bank, Credit Lyonnais, New
</TABLE>



                                       67
<PAGE>   68


<TABLE>
<S>               <C>
                  York Branch, ABN AMRO Bank N.V., General Electric Capital
                  Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis
                  Banque BFCE.

        10.3 -    Registration Rights Agreement dated as of March 31, 2000,
                  among Coho Energy, Inc., PPM America Special Investments Fund,
                  L.P., PPM America Special Investments CBO II, L.P., Appaloosa
                  Management L.P., as agent and on behalf of certain funds
                  including Appaloosa Investment Limited Partnership I, Palomino
                  Fund Ltd., and Tersk LLC; Pacholder Associates, Inc., as agent
                  and on behalf of certain funds including Pacholder Value
                  Opportunity Fund, L.P., High Yield Fund, Inc., One Group High
                  Yield Bond and Evangelical Lutheran Church in America Board of
                  Pensions; and Oaktree Capital Management, LLC, as general
                  partner of an investment manager for the entities set forth
                  therein (incorporated by reference to the Company's
                  Registration Statement on Form S-1 (Registration Number
                  333-96331)).

        10.4 -    Note Agreement dated as of March 31, 2000 among Coho Energy,
                  Inc., Coho Resources, Inc., Coho Louisiana Production Company,
                  Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate
                  Natural Gas Company, PPM America Special Investments Fund,
                  L.P., PPM America Special Investments CBO II, L.P., Appaloosa
                  Investment Limited Partnership I, Palomino Fund Ltd., Tersk
                  LLC, Oaktree Capital Management, LLC, Pacholder Value
                  Opportunity Fund, L.P., Pacholder High Yield Fund, Inc., One
                  Group High Yield Bond Fund, and Evangelical Lutheran Church in
                  America Board of Pensions (incorporated by reference to the
                  Company's Registration Statement on Form S-1 (Registration
                  Number 333-96331)).

        10.5 -    Securities Purchase Agreement dated as of March 31, 2000,
                  among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana
                  Production Company, Coho Exploration, Inc., Coho Oil & Gas,
                  Inc., Interstate Natural Gas Company, PPM America Special
                  Investments Fund, L.P., PPM America Special Investments CBO
                  II, L.P., Appaloosa Management, L.P., Oaktree Capital
                  Management, LLC, and Pacholder Associates, Inc. (incorporated
                  by reference to the Company's Registration Statement on Form
                  S-1 (Registration Number 333-96331)).

       *10.6 -    Employment Agreement dated as of April 1, 2000 by and among
                  Michael Y. McGovern and Coho Energy, Inc. (incorporated by
                  reference to the Company's Registration Statement on Form S-1
                  (Registration Number 333-96331)).

       *10.7 -    Employment Agreement dated as of April 1, 2000 by and among
                  Gary L. Pittman and Coho Energy, Inc. (incorporated by
                  reference to the Company's Registration Statement on Form S-1
                  (Registration Number 333-96331)).

       *10.8 -    Employment Agreement dated as of April 1, 2000 by and among
                  Gerald E. Ruley and Coho Energy, Inc. (incorporated by
                  reference to the Company's Registration Statement on Form S-1
                  (Registration Number 333-96331)).

       *10.9 -    Form of Stay Agreement entered into with each of John L.
                  Chadwick, Charles E. Gibson and Susan J. McAden.
</TABLE>



                                       68
<PAGE>   69


<TABLE>
<S>               <C>
        10.10 -   Letter agreement dated May 17, 2000 by and between Pirinate
                  Consulting Group, LLC and Coho Energy, Inc.

        10.11 -   Crude Oil Purchase Contract dated January 25, 1996, by and
                  between Coho Marketing and Transportation, Inc. and EOTT
                  Energy Operating Limited Partnership (incorporated by
                  reference to Exhibit 10.17 to the Company's Annual Report on
                  Form 10-K for the year ended December 31, 1995).

        10.12 -   Adoption Agreement for Coho Resources, Inc.'s Amended and
                  Restated 401(k) Savings Plan dated July 1, 1995 (incorporated
                  by reference to Exhibit 10.27 to the Company's Annual Report
                  on Form 10-K for the year ended December 31, 1998).

        10.13 -   Letter Agreement dated March 5, 1999, by and between Coho
                  Marketing and Transportation, Inc. and Eott Energy Operating
                  Limited Partnership, amending the Crude Oil and Purchase
                  Contract dated January 25, 1996, by and between Coho Marketing
                  and Transportation, Inc. and EOTT Energy Operating Limited
                  Partnership (incorporated by reference to Exhibit 10.27 to the
                  Company's Registration Statement on Form S-1 (Registration
                  Statement No. 333-96331)).

        10.14 -   Crude Oil Purchase Agreement dated October 1, 2000, by and
                  between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M).

        10.15 -   Crude Oil Purchase Agreement dated September 20, 2000, by
                  and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P.

        10.16 -   Crude Oil Purchase Contract dated December 19, 2000, by and
                  between Coho Resources, Inc. and EOTT Energy Operating Limited
                  Partnership.

        21.1  -   List of Subsidiaries of the Company (filed herewith).
</TABLE>

*    Represents management contract or compensatory plan or arrangement.

     The Company will furnish a copy of any exhibit described above to any
beneficial holder of its securities upon receipt of a written request therefor,
provided that such request sets forth a good faith representation that as of the
record date for the Company's 2001 Annual Meeting of Shareholders, such
beneficial holder is entitled to vote at such meeting, and upon payment to the
Company of a fee compensating the Company for its reasonable expenses in
furnishing such exhibits.

(b)  Reports on Form 8-K

     None.









                                       69
<PAGE>   70


                                   SIGNATURES

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

                                             Coho Energy, Inc.

Date: March 30, 2001                  By: /s/ MICHAEL MCGOVERN
                                          -------------------------------------
                                          Michael McGovern
                                          President and Chief Executive Officer

       Pursuant to the requirements of the Securities and 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.

<TABLE>
<CAPTION>
     SIGNATURE                                    TITLE                         DATE
     ---------                                    -----                         ----
<S>                                    <C>                                <C>
/s/ MICHAEL MCGOVERN                   President, Chief Executive         March 30, 2001
--------------------                     Officer and Director
Michael McGovern

/s/ GARY L. PITTMAN                    Vice President and Chief           March 30, 2001
--------------------                     Financial Officer
Gary L. Pittman

/s/ SUSAN J. MCADEN                    Controller and Chief               March 30, 2001
--------------------                     Accounting Officer
Susan J. McAden

/s/ EUGENE L. DAVIS                    Director                           March 30, 2001
--------------------
Eugene L. Davis

/s/ JOHN G. GRAHAM                     Director                           March 30, 2001
--------------------
John G. Graham

/s/ JAMES E. BOLIN                     Director                           March 30, 2001
--------------------
James E. Bolin

/s/ RONALD GOLDSTEIN                   Director                           March 30, 2001
--------------------
Ronald Goldstein

/s/ MICHAEL SALVATI                    Director                           March 30, 2001
--------------------
Michael Salvati
</TABLE>



                                       70
<PAGE>   71



                               INDEX TO EXHIBITS


<TABLE>
<CAPTION>
EXHIBIT
NUMBER       DESCRIPTION
-------      -----------
<S>          <C>
    2.1 -    Company's First Amended and Restated Chapter 11 Plan of
             Reorganization as filed with the United States Bankruptcy
             Court for the Northern District of Texas on February 14, 2000
             (incorporated by reference to Exhibit 2.1 to the Company's
             Registration Statement on Form S-1 (Registration Number
             333-96331)).

    2.2 -    First Amended and Restated Disclosure Statement with respect
             to the Joint Plan of Reorganization under Chapter 11 of the
             United States Bankruptcy Code as filed with the United States
             Bankruptcy Court for the Northern District of Texas on
             February 14, 2000 (incorporated by reference to Exhibit 2.2 to
             the Company's Registration Statement on Form S-1 (Registration
             Number 333-96331)).

    2.3 -    Findings of Fact, Conclusions of Law, and Order Confirming
             Debtors' First Amended and Restated Chapter 11 Plan of
             Reorganization as filed with the United States Bankruptcy
             Court for the Northern District of Texas on March 20, 2000
             (incorporated by reference to the Company's Registration
             Statement on Form S-1 (Registration Number 333-96331).

    3.1 -    Form of Amended and Restated Articles of Incorporation of
             the Company (incorporated by reference to the Company's
             Registration Statement on Form S-1 (Registration Number
             333-96331)).

    3.2 -    Form of Amended and Restated Bylaws of the Company
             (incorporated by reference to the Company's Registration
             Statement on Form S-1 (Registration Number 333-96331)).

    4.1 -    Form of Amended and Restated Articles of Incorporation
             (included as Exhibit 3.1 above).

    4.2 -    Form of Amended and Restated Bylaws of the Company (included
             as Exhibit 3.2 above).

   10.1 -    Credit Agreement dated as of March 31, 2000, among Coho
             Energy, Inc., The Chase Manhattan Bank, Meespierson Capital
             Corp., Fleet National Bank, Credit Lyonnais, New York Branch,
             ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC
             Inc., Credit Agricole Indosuez, and Natexis Banque BFCE
             (incorporated by reference to the Company's Registration
             Statement on Form S-1 (Registration Number 333-96331)).

   10.2 -    First Amendment to Credit Agreement dated November 27, 2000
             among Coho Energy, Inc., The Chase Manhattan Bank, Meespierson
             Capital Corp., Fleet National Bank, Credit Lyonnais, New York
             Branch, ABN AMRO Bank N.V., General Electric Capital Corporation,
             CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE.
</TABLE>


<PAGE>   72


<TABLE>
<S>          <C>
   10.3 -    Registration Rights Agreement dated as of March 31, 2000,
             among Coho Energy, Inc., PPM America Special Investments Fund,
             L.P., PPM America Special Investments CBO II, L.P., Appaloosa
             Management L.P., as agent and on behalf of certain funds
             including Appaloosa Investment Limited Partnership I, Palomino
             Fund Ltd., and Tersk LLC; Pacholder Associates, Inc., as agent
             and on behalf of certain funds including Pacholder Value
             Opportunity Fund, L.P., High Yield Fund, Inc., One Group High
             Yield Bond and Evangelical Lutheran Church in America Board of
             Pensions; and Oaktree Capital Management, LLC, as general
             partner of an investment manager for the entities set forth
             therein (incorporated by reference to the Company's
             Registration Statement on Form S-1 (Registration Number
             333-96331)).

   10.4 -    Note Agreement dated as of March 31, 2000 among Coho Energy,
             Inc., Coho Resources, Inc., Coho Louisiana Production Company,
             Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate
             Natural Gas Company, PPM America Special Investments Fund,
             L.P., PPM America Special Investments CBO II, L.P., Appaloosa
             Investment Limited Partnership I, Palomino Fund Ltd., Tersk
             LLC, Oaktree Capital Management, LLC, Pacholder Value
             Opportunity Fund, L.P., Pacholder High Yield Fund, Inc., One
             Group High Yield Bond Fund, and Evangelical Lutheran Church in
             America Board of Pensions (incorporated by reference to the
             Company's Registration Statement on Form S-1 (Registration
             Number 333-96331)).

   10.5 -    Securities Purchase Agreement dated as of March 31, 2000,
             among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana
             Production Company, Coho Exploration, Inc., Coho Oil & Gas,
             Inc., Interstate Natural Gas Company, PPM America Special
             Investments Fund, L.P., PPM America Special Investments CBO
             II, L.P., Appaloosa Management, L.P., Oaktree Capital
             Management, LLC, and Pacholder Associates, Inc. (incorporated
             by reference to the Company's Registration Statement on Form
             S-1 (Registration Number 333-96331)).

  *10.6 -    Employment Agreement dated as of April 1, 2000 by and among
             Michael Y. McGovern and Coho Energy, Inc. (incorporated by
             reference to the Company's Registration Statement on Form S-1
             (Registration Number 333-96331)).

  *10.7 -    Employment Agreement dated as of April 1, 2000 by and among
             Gary L. Pittman and Coho Energy, Inc. (incorporated by
             reference to the Company's Registration Statement on Form S-1
             (Registration Number 333-96331)).

  *10.8 -    Employment Agreement dated as of April 1, 2000 by and among
             Gerald E. Ruley and Coho Energy, Inc. (incorporated by
             reference to the Company's Registration Statement on Form S-1
             (Registration Number 333-96331)).

  *10.9 -    Form of Stay Agreement entered into with each of John L.
             Chadwick, Charles E. Gibson and Susan J. McAden.
</TABLE>


<PAGE>   73
<TABLE>
<S>          <C>
   10.10 -   Letter agreement dated May 17, 2000 by and between Pirinate
             Consulting Group, LLC and Coho Energy, Inc.

   10.11 -   Crude Oil Purchase Contract dated January 25, 1996, by and
             between Coho Marketing and Transportation, Inc. and EOTT
             Energy Operating Limited Partnership (incorporated by
             reference to Exhibit 10.17 to the Company's Annual Report on
             Form 10-K for the year ended December 31, 1995).

   10.12 -   Adoption Agreement for Coho Resources, Inc.'s Amended and
             Restated 401(k) Savings Plan dated July 1, 1995 (incorporated
             by reference to Exhibit 10.27 to the Company's Annual Report
             on Form 10-K for the year ended December 31, 1998).

   10.13 -   Letter Agreement dated March 5, 1999, by and between Coho
             Marketing and Transportation, Inc. and Eott Energy Operating
             Limited Partnership, amending the Crude Oil and Purchase
             Contract dated January 25, 1996, by and between Coho Marketing
             and Transportation, Inc. and EOTT Energy Operating Limited
             Partnership (incorporated by reference to Exhibit 10.27 to the
             Company's Registration Statement on Form S-1 (Registration
             Statement No. 333-96331)).

   10.14 -   Crude Oil Purchase Agreement dated October 1, 2000, by and
             between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M).

   10.15 -   Crude Oil Purchase Agreement dated September 20, 2000, by
             and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P.

   10.16 -   Crude Oil Purchase Contract dated December 19, 2000, by and
             between Coho Resources, Inc. and EOTT Energy Operating Limited
             Partnership.

   21.1  -   List of Subsidiaries of the Company (filed herewith).
</TABLE>

*    Represents management contract or compensatory plan or arrangement.

     The Company will furnish a copy of any exhibit described above to any
beneficial holder of its securities upon receipt of a written request therefor,
provided that such request sets forth a good faith representation that as of the
record date for the Company's 2001 Annual Meeting of Shareholders, such
beneficial holder is entitled to vote at such meeting, and upon payment to the
Company of a fee compensating the Company for its reasonable expenses in
furnishing such exhibits.