<PAGE>
                                  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, 2001
                                             -----------------

                                       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                                             75254
---------------------------------------                 ----------
(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 Sections 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 28, 2002, 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 $42,000 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.


<PAGE>

                                TABLE OF CONTENTS

<Table>
<Caption>

                                                                                                     PAGE
                                                                                                     ----
<S>                                                                                                  <C>
PART I

Item 1.   Business................................................................................... 4
Item 2.   Properties................................................................................. 4
Item 3.   Legal Proceedings..........................................................................25
Item 4.   Submission of Matters to a Vote of Security Holders........................................26

PART II

Item 5.   Market for Registrant's Common Equity and Related Stockholder Matters......................27
Item 6.   Selected Financial Data....................................................................28
Item 7.   Management's Discussion and Analysis of Financial Condition and
          Results of Operations......................................................................29
Item 7A.  Quantitative and Qualitative Disclosure about Market Risk..................................44
Item 8.   Consolidated Financial Statements..........................................................46
Item 9.   Changes in and Disagreements with Accountants on Accounting and
          Financial Disclosure.......................................................................73

PART III

Item 10.  Directors and Executive Officers of the Registrant.........................................74
Item 11.  Executive Compensation.....................................................................75
Item 12.  Security Ownership of Certain Beneficial Owners and Management.............................81
Item 13.  Certain Relationships and Related Transactions.............................................82

PART IV

Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K............................85
</Table>


                                       2
<PAGE>



                           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 crude 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 outcome of our bankruptcy proceedings and restrictions that may be
          placed on our operations during the pendency of the proceedings;

     o    the substantial amount of our indebtedness;

     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; 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 6 for a list of definitions of certain industry terms used
throughout this document.



                                       3
<PAGE>

                                     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, 2001, our total proved
reserves were 90.6 MMBOE with a net present value of proved reserves discounted
at 10% of $352.4 million, approximately 70% of which were proved developed
reserves, based on year end market prices of $19.84 per barrel for crude oil and
$2.57 per MMbtu for natural gas. Approximately 96% of our total proved reserves
were comprised of crude oil. At December 31, 2001, our operations were conducted
in 19 major producing fields, 16 of which we operate. 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 subsidiaries Coho Resources,
Inc. and Coho Oil & Gas, 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 75254, and our telephone number is (972)
774-8300.

RECENT HISTORY AND BANKRUPTCY PROCEEDINGS

     We have carried a high level of indebtedness since emerging from bankruptcy
in March 2000 with a ratio of consolidated indebtedness to total capitalization
of 78% at March 31, 2000 and 82% at December 31, 2001. In April 2001, we entered
into an agreement with JP Morgan, a division of Chase Securities, to act as our
financial advisor in evaluating various potential strategic transactions to
reduce our high level of indebtedness including:

     o    various potential recapitalization transactions;

     o    the sale of a portion of our company to provide working capital for
          our remaining properties; or

     o    the sale of all of our company.

     In September and October 2001, we engaged in active negotiations with a
third party for the sale of our Mississippi properties for $80 million but we
were unable to close the transaction.

     During 2001, we continued with our operating business strategy that focused
on relatively low-risk development activities. We expected this development
activity to generate increases in production, cash flow from operations and
proved developed reserves. Our development activity was successful in increasing
production and cash flow from operations but not at the levels we had expected
and not at levels sufficient to offset declines in crude oil and natural gas
prices during the year combined with higher operating costs. Our development
activity was also not successful in increasing proved developed reserves as
discussed more fully under "Oil and Gas Operations."

     On November 1, 2001, the lenders under the senior revolving credit facility
notified us that our borrowing base under this facility had been redetermined in
the semi-annual review from $195 million to $175 million effective November 1,
2001. On November 2, 2001, we received a notice of borrowing base deficiency
because borrowings under the credit facility exceeded the redetermined borrowing
base by $20 million. In December 2001, we hired a new financial advisor, CIBC
World Markets Corp., to assist us in developing a strategy to address our
liquidity problems since JP Morgan, as one of our bank lenders, could no longer
serve in this capacity. We did not have sufficient working capital to cure the
borrowing base deficiency within the 90-day cure period and on February 1, 2002
a notice of default was issued by the lenders under the senior revolving credit
facility.

     On February 6, 2002, we and our wholly owned subsidiaries, Coho Resources,
Inc. and Coho Oil & Gas, Inc., filed a voluntary petition for relief under
Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for
the Northern District of Texas. The bankruptcy petitions were filed to protect
us while we develop a solution to our liquidity problems. We are currently
operating as debtor-in-possession under the court's supervision



                                       4
<PAGE>


and pursuant to the court's orders. We filed schedules with the bankruptcy court
on March 8, 2002. Those schedules contain our unaudited, and in some cases,
estimated assets and liabilities as of February 6, 2002, as shown by our
accounting records.

     Under our cash collateral order, we have agreed with the lenders under the
senior credit facility to develop a marketing plan with our new financial
advisor, CIBC, for the sale of our assets or a recapitalization of our debt and
equity. We, together with CIBC, are currently working with our bank group and
the unsecured creditors committee on mutually acceptable terms for this
marketing plan to achieve maximum value for our assets in this process. We
expect that once finalized and approved, the marketing plan will allow us to
explore other alternatives available to us, in addition to a sale of our assets,
including a recapitalization of our debt and equity assuming we are able to
raise sufficient equity from existing or new investors to cure the $20 million
borrowing base deficiency under our credit facility and to provide working
capital to develop our properties. A recapitalization may include a partial sale
of our assets. Any sale or recapitalization will be subject to bankruptcy court
approval under a Chapter 11 plan of reorganization or liquidation or in
accordance with Section 363 of the bankruptcy code, which generally provides for
a partial sale of assets prior to confirmation of a plan of reorganization or
liquidation.

     At this time, it is not possible to predict the outcome of the bankruptcy
proceedings, in general, or the effect on our business or on the interests of
the creditors or shareholders. We believe, however, that it may not be possible
to satisfy in full all of the claims against us. In addition, the shareholders
of our company may not realize any value on their investment. As a result of the
bankruptcy filing, all of our liabilities incurred prior to February 6, 2002,
including secured debt, are subject to compromise. Under the bankruptcy code,
payment of these liabilities may not be made except pursuant to a plan of
reorganization or liquidation or bankruptcy court approval.

     The financial statements do not include any adjustments relating to the
recoverability and classification of asset carrying amounts (including $333
million in net property, plant and equipment) or the amount and classification
of liabilities that might result should we be unable to continue as a going
concern. Our ability to continue as a going concern is dependent upon the
confirmation of a plan of reorganization, adequate sources of capital and the
ability to sustain positive results of operations and cash flows sufficient to
continue to explore for and develop proved oil and gas reserves. These factors,
among others, raise substantial doubt concerning our ability to continue as a
going concern.

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.

     Louisiana. On December 2, 1998, we sold our natural gas assets located in
Monroe, Louisiana, for a net sales price of $61.5 million. The assets sold
represented approximately 14% of our year end 1997 proved reserves and included
two gas gathering systems.

     March 2000 Reorganization. On August 23, 1999, we and our then 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.


                                       5
<PAGE>


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 senior 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.

     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 owned approximately 88% of our new common stock after the
reorganization and owned $65.5 million of the outstanding senior subordinated
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.

     Effective December 31, 2000, Coho Exploration, Inc., Coho Louisiana
Production Company and Interstate Natural Gas were merged into Coho Resources,
Inc. and ceased to exist as separate entities.

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.



                                       6
<PAGE>

     "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.

     "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

     Since emerging from bankruptcy in March 2000, we have focused our capital
expenditures 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 expected to generate increases
in production and cash flow from operations and to increase our proved developed
producing reserves by developing our proved undeveloped reserves.

     Our capital expenditure program implemented over the last 18 months
included development activities in Mississippi together with a few exploration
opportunities in Oklahoma that we anticipated would provide increases in
production in the near term to provide the necessary cash flow to support our
longer term waterflood development activities in Oklahoma. Unfortunately, the
production increases we achieved from these short-term development activities in
Mississippi and exploration activities in Oklahoma did not meet our expectations
and did not substantially increase our production, which was partially due to
normal production declines, primarily in our Mississippi fields.

     During 2002, we will continue this development strategy, but on a smaller
scale due to capital constraints, with a focus on opportunities with near term
production increases. Due to our capital constraints, our emphasis will be on
maintaining existing production and trying to offset normal production declines.



                                       7
<PAGE>

     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 2001, we conducted our
operations mainly on the following fields:

     o    Mississippi - Brookhaven, Martinville and Soso; and

     o    Oklahoma - Tatums, East Fitts, East Velma Middle Block, Eola, and
          Jennings Deese.

     Our capital expenditures totaled $6.3 million in 1999, $25.3 million in
2000, and $33.2 million in 2001. 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 23 gross or 15.8 net
development wells with a success rate of 87%. In 2001, we continued with this
capital plan and drilled a total of 35 gross or 26 net wells with a success rate
of 91%. We also participated in the drilling of seven gross, or .2 net wells
that were completed as oil producers in two outside operated Oklahoma properties
during 2001. We plan to continue development drilling and recompletion activity
on a substantially reduced basis in 2002 due to expenditure constraints imposed
by our cash collateral order under our current bankruptcy proceedings.

     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
these 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. We have
concentrated on the full development of mature fields that 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, as well as water from supplementary sources, is
re-injected into the reservoir creating a so-called water-drive mechanism to
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. Prior to
2000 we successfully developed six of these projects and during 2000, we
initiated work on a seventh project in the Brookhaven field. Based on the
results of this recent waterflood project in the Brookhaven field we have
selected several other areas in the field which should present opportunities to
further develop secondary reserves using existing well bores and facilities.

     The acquisition of the Oklahoma properties in 1997 presented us with nine
existing secondary projects and we have identified 14 additional potential
secondary projects on these properties. During 2000 and 2001, we initiated work
on nine of these 14 waterflood projects. In late 2000, we initiated the
installation of facilities and conversion or repair of available well bores to
serve the Sims and Humphreys reservoirs in the East Velma Middle Block Unit with
work continuing throughout 2001. In 2001, we initiated two new pilot waterflood
projects in the Bumpass Unit to serve the Goodwin and Flattop reservoirs to
evaluate their response to water injection and determine the economic
feasibility of installing a complete waterflood project. In addition, pilot
waterflood projects were initiated to further explore the potential for
additional secondary reserve recovery in the Jennings Deese Unit, Graham Deese
Unit, North Alma Deese Unit, Tatums Unit and East Fitts Unit which were under
waterflood operations at the time they were acquired in late 1997. The purpose
of these pilot waterflood projects is to determine the potential for improving
the waterflood performance of the existing reservoirs, which are believed to
have not been subjected to




                                       8
<PAGE>

effective water injection by the current on-going waterflood in these fields.
Early indications, based upon evidence of response, are that the pilot
waterfloods will demonstrate that additional reserves can be recovered at
economically attractive levels by concentrating higher pressure, increasing
density, or modifying of the existing waterflood projects.

     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 in the Martinville and Laurel
fields resulting in 37 square miles and 24 square miles of data, respectively,
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 excellent opportunities to
utilize this data to explore for new sources of supply in areas where we are
familiar with the overall geologic picture and hydrocarbon trapping mechanisms.

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, 2001, and the number of
productive wells producing at December 31, 2001.


<Table>
<Caption>

                    Year Ended December 31(a)                                     At December 31, 2001
                --------------------------------      ------------------------------------------------------------------------------
                 1999         2000         2001
                ------       ------       ------
                                                                      Productive Wells
                                                      ------------------------------------------------
                                                           Gross Wells                 Net Wells          Percentage       Average
                                                      ----------------------    ----------------------   of Net 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      4,621        4,725        5,016          140            2          131            2          98%            96%
Oklahoma         5,414        5,598        5,617        1,389          126          509           47          91%            41%
Other              315          285          212           21            2            9            2          18%            48%
                ------       ------       ------        -----          ---          ---           --

     Total      10,350       10,608       10,845        1,550          130          649           51
                ======       ======       ======        =====          ===          ===           ==
</Table>

     (a) In response to depressed crude oil prices during early 1999, we
significantly reduced minor and major repairs and drilling activity on our
operated properties, ceased all repair work and drilling activity 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, 2001, 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
and we should be able to recover additional reserves not yet developed through
detailed study and exploitation of these properties. In 2001, we drilled a total
of 29 gross wells. We drilled two dry holes in the drilling program, which
resulted in a successful completion rate of 93%. One dry hole was drilled in the
Eola field at a total depth of 2,250 feet and the other dry hole was drilled in
the Tatums field at a depth of 3,001 feet. Both dry holes were attempts to drill
for shallow infield pay intervals, which were found to be unattractive for
commercial production and were abandoned without attempting to complete the
wells. The largest number of wells drilled in a particular field were the 16
wells drilled in the Tatums Field, including the one dry hole mentioned earlier,
where we have a 49% working interest. One of the more significant wells was
drilled in the Eola field to test a new fault block by re-entering an existing
well and



                                       9
<PAGE>


directionally drilling to the objective in the McLish and Bromide sands. This
well was completed in March 2001 and had an initial production rate of 275 BOE
per day gross, or 238 BOE per day net. Two offset locations were subsequently
drilled as a result of the subsurface control gained by the drilling of the
initial well and as of December 2001, these were in the early stages of being
tested and stimulation plans were being formulated to treat these wells in early
2002. After stimulating both wells, the combined initial production rate is 60
BOE per day net to our interest which is significantly below our expected levels
for these wells. The remaining drilling in 2001 was in the East Fitts field with
four wells drilled and the Jennings Deese primary field with five wells drilled.

     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%.

     The East Fitts field is our largest property in Oklahoma and as of December
2001 had a total of 129 gross producing wells, 73 gross service wells and a
total of 79 gross inactive wells. The field is primarily an oil producer and a
waterflood has been active in the field for a number of years.

     In 2001, we continued the infill drilling program that had been initiated
in 2000. This infill drilling program is designed to recover unswept oil
reserves from areas of the reservoir by increasing the density of the drilling
pattern from the historic ten-acre development to a five-acre drainage pattern.
A total of four wells were drilled in 2001, as part of this infill project and
resulted in three producers and one of the wells encountered a high pressure
waterflow and was abandoned with the plan to re-enter at a later date with
suitable drilling equipment and continue the completion. The three wells drilled
and completed were the EFU 13-7, 26-3, and 26-4. The well, which was abandoned
with plans to complete it later, was the EFU 13-8. The net daily initial
combined production rate from the three wells drilled was 144 BOE, and the
success of these wells further confirmed that there are areas of high oil
saturation between the existing waterflood pattern and the new higher density
well pattern. As a result of these findings, there are over 80 identified
drilling locations, which could be suited to this higher density well pattern in
the existing limits of the East Fitts field.

     In addition to the in-field drilling program, we concentrated on improving
the water injection effectiveness within the East Fitts field by activating and
repairing injection pumping equipment to increase our capacity. In 2001, we
increased water injection volumes by approximately 14,000 barrels of water per
day and brought the total daily water injection up to approximately 84,000
barrels. The additional injection is expected to provide us with better sweep
efficiency in the existing waterflood and thus increase recovery and daily
production rates. The field had an average net daily production of 1,252 BOE in
2001, which was an approximate 6% increase over the average net daily production
of 1,182 BOE seen in 2000.

     Net proved reserves at December 31, 2001, totaled 22.7 MMBOE, which
represented approximately 25% of our total net proved reserves, as compared to
year-end net proved reserves at December 31, 2000 of 23.1 MMBOE. The reduction
in net proved reserves from 2000 to 2001 was due primarily to reserves produced
during 2001.

     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 61%.

     In 2000, work was initiated to install a waterflood secondary production
operation in the field to recover reserves that had not been produced under
primary production methods. The East Velma Middle Block sits between two other
outside operated properties on this same structure that had been waterflooded
with excellent success. We began work in 2000 and were able to commence water
injection operations on a limited scale. We have now completed the conversion of
17 wells to injection service and have completed six water supply wells. We are
currently injecting a total of approximately 16,700 barrels of water per day. In
2001, we laid a water supply line from wells in an offset field, to provide
increased water supply. This supply line is to commence operation in the first
quarter of 2002 and is expected to increase our injection volumes by up to
25,000 barrels of water per day. We spent a total of roughly $2.7 million on the
East Velma Middle Block in 2001 and completed the major portion of the project
on the western half of the unit. We plan to spend $1.5 million during 2002 to
complete the western half of the unit and to continue the waterflood
installation in the eastern half of the unit. We estimate that an additional $2
million will be required in 2003 to complete the installation of the waterflood
facilities in the eastern portion of the unit.



                                       10
<PAGE>

     Proved net reserves totaled 10.6 MMBOE as of December 31, 2001,
representing approximately 13% of our total proved reserves, as compared to
proved net reserves of 11.6 MMBOE at December 31, 2000. The decrease in net
proved reserves is primarily due to:

     o    downward revisions of natural gas reserves because some gas wells were
          converted to water injection wells for the waterflood project;

     o    decreases in the value of reserves related to lower crude oil and
          natural gas prices between years; and

     o    reserves produced during 2001.

Daily average net production from the East Middle Block field in 2001 averaged
462 BOE down from the 516 BOE experienced in 2000. Although the overall net
production average for 2001 was below the 2000 level, we have seen production
improvements in the later half of 2001 indicating that we are seeing production
response from water injection. We anticipate further production response in 2002
as we significantly increase daily water injection volumes.

     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 3,000 feet. Our average
working interest in the Tatums field is 49%.

     As of December 2001, there were 112 gross producing wells and 55 gross
water injection or service wells active in the field. In addition, there are 66
gross available wellbores, which are currently inactive in the field.

     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 in the Deese reservoir, which had not been previously recognized. We
began an in-field development drilling program during 2000 and drilled a total
of eleven gross wells confirming that high oil saturations remained in the areas
delineated by the reprocessed seismic. In 2001, we continued on this drilling
project and drilled a total of 16 gross wells, with one dry hole, which we did
not attempt to complete. In order to supply this new drilling area with water
injection to re-pressure the reservoir and recover the remaining oil, we
expanded the existing water injection facilities and lines to extend into this
area. We are currently injecting water into the extended area of the field.
Based on the success of these injection efforts, we plan to continue to develop
this area through additional drilling in 2002.

     Net daily production from the Tatums field in 2001 averaged 669 BOE,
representing an increase of 12%, as compared to average net daily production of
597 BOE in 2000. The Tatums field also had a 12% increase in average net daily
production from 1999 to 2000. Total net proved reserves as of December 31, 2001
were 3.9 MMBOE, as compared to total net proved reserves as of December 31, 2000
of 3.5 MMBOE. Net proved reserves have increased in 2000 and 2001 by 7% and 10%,
respectively.

     Other Oklahoma. We operate seven other fields in Oklahoma:

     o    Bumpass (Carter County; working interest 63%);

     o    Cox Penn (Carter County; working interest 99%);

     o    Eola (Garvin County; working interest 87%);

     o    Graham Deese (Carter County; working interest 63%);

     o    Jennings Deese (Carter County; working interest 85%);

     o    North Alma Deese (Stephens County; working interest 96%); and

     o    Sholem Alechem Fault Block "A" (Stephens County; working interest
          87%).



                                       11
<PAGE>

As discussed under "Secondary Recovery", we launched pilot waterflood projects
in the North Alma Deese, Graham Deese and Bumpass fields during 2000 and
continued work on these projects during 2001. Continued monitoring of these
waterflood projects for response while we continue to inject water and optimize
lifting equipment to handle increased production will be our focus in 2002 due
to capital constraints.

     Total average net daily production in 2001 from these fields was 2,403 BOE,
a 3% increase, as compared to average net daily production of 2,330 BOE in
2000. At December 31, 2001, net proved reserves in these fields were
approximately 26.4 MMBOE as compared to net proved reserves of 28.0 MMBOE at
December 31, 2000. The 6% decline in reserves between years is due to reserves
produced during 2001 and lower crude oil and natural gas prices used in the
reserve evaluation at December 31, 2001.

     We also have working interests in producing properties that are operated by
other companies. These properties are located in various counties in Oklahoma
with the primary counties being Stephens, Garvin and Carter. At December 31,
2001, net proved reserves in these fields were estimated at 2.1 MMBOE as
compared to net reserves of 2.7 MMBOE at December 31, 2000. The 25% decline in
reserves between the comparable periods is due to lower crude oil and natural
gas prices used in the reserve evaluation at December 31, 2001 as compared to
yearend 2000 and reserves produced during 2001. Net average daily production
from these properties was 832 BOE in 2001 as compared to average net daily
production of 973 BOE in 2000.

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. 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 Fredericksburg, Paluxy and Rodessa formations through
deeper exploratory drilling. The Brookhaven field produces some of our highest
quality crude oil in the State of Mississippi which results in higher prices.

     In 2001, we drilled the BFU 32N-15 Well No. 1 at a cost of approximately
$928,000 to a total depth of 13,700 feet in an attempt to extend the production
limits of the Washita Fredericksburg formation based upon 2-D seismic available
in the area and the successful completion of the BFU 5-2 Well No. 2 in 2000 with
an initial daily production rate of 288 BOE per day gross or 205 BOE per day
net. The well was not completed as the expected geologic structure was found
structurally lower and non-commercial. The well was plugged without any attempt
to make a completion or test. Subsequent analysis of the seismic interpretation
showed that a velocity anomaly existed in this area of the field, which caused
the seismic interpretation to indicate a structural high that did not exist.

     In late 2000, we initiated a secondary project as a pilot waterflood
operation to evaluate the potential of initiating water injection efforts in
selected areas of the Tuscaloosa reservoir which were believed to have not been
effectively drained by past production methods. In 2001, we spent a total of
$1.5 million to install water injection pumps, injection lines and facilities to
serve this project. Included in the expenditure was the conversion of two wells
to serve as water injection wells, and an additional three available wellbores
have been completed as producing wells for the project. We are currently
injecting 600 barrels of water a day into this project and are producing
approximately 100 BOPD as a response to this waterflood installation. The
performance of this project has enabled us to add approximately 180 MBbls of
proved producing reserves. Based on these results, we plan to initiate a new
waterflood in 2002 by converting two additional available wellbores to serve as
water injection wells. We have identified a minimum of two other distinct areas
where we expect waterflooding operations to have the same favorable results as
in the Brookhaven field, and we intend to develop engineering designs to
recommend their development as capital becomes available.

     In 2001, the total net daily average production from the Brookhaven field
was 716 BOE, an increase of approximately 39% over the 514 BOE net daily average
production in 2000. Net proved reserves at December 31, 2001 were 4.1 MMBOE
reflecting a decline of 21% from net proved reserves of 5.2 MMBOE at December
31, 2000. The reduction in reserves is primarily due to downward revisions in
reserves due to the unsuccessful drilling of the BFU 32N-15 Well No. 1,
discussed previously, together with decreases in reserves related to reserves
produced during 2001 and lower crude oil and natural gas prices at year end 2001
as compared to year end 2000.



                                       12
<PAGE>

     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 structure known
as a "salt dome" with known hydrocarbon production formations ranging in depth
from 7,500 feet to 13,500 feet. The Laurel field is our largest oil producing
property and represented approximately 41% of our total Mississippi production
on a BOE basis in 2001.

     In 2001, we concentrated our work on maintaining production from existing
wells and improving the effectiveness of the secondary recovery projects that
were underway in the field. There were no wells drilled in the Laurel field
during 2001, although several locations were identified and initial plans did
include the drilling of two locations. However, the decline in crude oil and
natural gas prices during the year caused us to eliminate the drilling program
in 2001. In 2001, we completed 21 well repairs and three recompletions.

     The average net daily production in 2001 from the Laurel field was 2,058
BOE representing a decrease in average net daily production of 7% from the same
period in 2000. The primary reason for the decrease in production was due to
normal production declines. As of December 31, 2001, net proved reserves were
estimated at 8.5 MMBOE representing a decrease of approximately 14% from the
December 31, 2000 year end reserves. The decrease in reserves is a result of the
lower crude oil and natural gas prices at year end 2001 as compared to year end
2000 and production of reserves during 2001.

     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
productive limits of the field are estimated to cover more than 7,400 acres and
at year end 2001, contained a total of 47 gross wells with 18 wells being
operated as producing wells. The field is a complex deep-seated anticline
geologic structure marked by extensive faulting and multiple productive
horizons. The field consists of numerous hydrocarbon producing formations
ranging in depth from approximately 8,500 to 14,500 feet.

     In 2001, we drilled two wells to develop reserves and both were
successfully completed as producing oil wells. The combined initial net daily
production rate from the two wells was 202 BOE. The remainder of our activity in
the Martinville field during 2001 was concentrated on performing well repairs
and recompletions on existing wells. In 2001, we completed seven well repairs
and performed eight recompletion projects.

     Net proved reserves at year end 2001 totaled 3.1 MMBOE, a decrease of 23%
from year end 2000. The decrease in reserves is primarily due to a reduction in
reserves due to lower crude oil and natural gas prices at December 31, 2001 and
reserves produced during 2001. Production in 2001 averaged a daily net of 667
BOE and represented an increase of approximately 3% from the average daily net
production for 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 concentrated the majority of our efforts to initiate
and manage a water injection program for the Cotton Valley, Sligo and Rodessa
formations, which were previously producing in the field under primary recovery
methods. In 2001, we drilled two development wells to provide additional
recovery in the Cotton Valley reservoir and to take advantage of the water sweep
being provided by the water injection program. These two wells were completed as
oil producers with a combined initial net daily production rate of 137 BOE. The
results from these two Cotton Valley wells were disappointing since our expected
combined initial production rate was 600 BOE per day. Additional activity in
2001 centered on well repairs and recompletion work to maintain production. A
total of nine recompletions and 10 well repairs were completed in 2001.

     Net proved reserves at year end 2001 totaled 3.7 MMBOE and represented a
decrease of 27% in net proved reserves from the prior year. The decrease in
reserves is due primarily to downward revisions in reserves related to the
Cotton Valley wells drilled in 2001 together with decreases in reserves related
to production of reserves during



                                       13
<PAGE>

2001 and lower crude oil and natural gas prices at December 31, 2001. The poor
drilling results on the two Cotton Valley wells resulted in a reduction in
proved reserves of 464 MBOE. Additionally, we had attributed reserves of 234
MBOE in the Hosston formation that were proved non productive by drilling these
wells.

     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
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, 2001, we operated 19 gross producing wells.

     In 2001, we directed our activity toward well repairs and recompletions in
an effort to maintain production. We conducted a total of seven well repairs and
seven recompletions. Average daily net production for 2002 for the Summerland
field was 774 BOE or an increase of 8% from the average daily net production for
2001.

     At December 31, 2001, the Summerland field had proved reserves of 2.6
MMBOE, a decrease of approximately 34% from year end 2000. This decrease was
primarily due to lower crude oil and natural gas prices at December 31, 2001 as
compared to year 2000, poor production results from the recompletions performed
in 2001 and reserves produced during 2001.

OTHER DOMESTIC PROPERTIES

      We also have working interests in other producing properties in
Mississippi and Texas. We operate the Bentonia (99% working interest) and
Cranfield (100% working interest) fields in Mississippi and four gas wells in
Navarro County, Texas (100% working interest) and we own non-operated working
interests in the Glazier field (39% working interest) in Mississippi, the
Clarksville field (43% working interest) in Texas and a field in Federal waters
offshore North Padre Island, Texas (39% working interest). At year end 2001, we
removed all proved reserves (453 MBOE) for the North Padre Island Block A-59,
which is operated by El Paso Production due to the lack of success in attempts
to workover the well in 2001. As of December 31, 2001, these fields had combined
net proved reserves of 2.8 MMBOE as compared to 3.6 MMBOE at December 31, 2000.
Aggregate average daily net production from these properties for 2001 was
approximately 420 BOE as compared to 427 BOE for 2000.

TUNISIAN OPERATIONS

     We decided to discontinue our participation in the exploration of two
Tunisia, North Africa permits due to capital commitments during 2001 exceeding
$7 million net to our interest. The two subsidiaries, Coho Anaguid, Inc. and
Coho International Limited, that own these permits filed for protection under
Chapter 11 of the United States Bankruptcy Code on February 20, 2001. During May
2001, Coho International entered into a settlement agreement with the other
joint owners in the permit area. Under this agreement, Coho International
assigned its interest in the Fejaj permit to the other joint owners in exchange
for the assumption by the other joint owners of Coho International's existing
obligations and existing payables under the permit. During July 2001, Coho
Anaguid, Inc. entered into a definitive agreement to sell all of its interest in
the Anaguid permit to Pioneer Natural Resources Company and the other joint
owners in the permit area for cash proceeds of approximately $200,000 and the
assumption of Coho Anaguid's obligations under the permit totaling in excess of
$7 million. These sales agreements have been approved by the United States
Bankruptcy Court and the Tunisian government. We converted the bankruptcy
proceedings for Coho Anaguid and Coho International from Chapter 11
reorganization proceedings to Chapter 7 liquidation proceedings during the first
quarter of 2002 to wind down these proceedings.

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, 2001:



                                       14
<PAGE>



<Table>
<Caption>
                                                            Year Ended December 31,
                                                      ---------------------------------
                                                        1999          2000       2001
                                                      -------       --------    -------
<S>                                                   <C>           <C>         <C>
CRUDE OIL:
  Volumes (MBbls) ................................      3,343          3,535      3,689
  Average sales price (per Bbl)(a) ...............    $ 15.40       $  23.31    $ 19.25
NATURAL GAS:
  Volumes (MMcf) .................................      2,608          2,087      1,616
  Average sales price (per Mcf)(b) ...............    $  2.24       $   3.73    $  3.68
AVERAGE PRODUCTION COST (PER BOE)(c) .............    $  5.60       $   7.55    $  7.57
DEPRECIATION AND DEPLETION COST (PER BOE) ........    $  3.63       $   3.94    $  4.50
</Table>

(a)  Includes the effects of crude oil price hedging contracts. Price per
     Bbl before the effect of hedging was $15.40 for the year ended December 31,
     1999, $26.10 for the year ended December 31, 2000 and $20.66 for the year
     ended December 31, 2001.

(b)  Includes the effects of natural gas price hedging contracts. Price per Mcf
     before the effect of hedging was $2.24 for the year ended December 31,
     1999, $3.99 for the year ended December 31, 2000 and $4.38 for the year
     ended December 31, 2001.

(c)  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 of Financial
     Condition and 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,
                                  ----------------------------------------------------------------
                                        1999                   2000                     2001
                                  ----------------       ----------------         ----------------
                                  Gross        Net       Gross       Net          Gross       Net
                                  -----        ---       -----       ----         -----       ----
<S>                               <C>          <C>       <C>         <C>          <C>         <C>
EXPLORATORY:
  Crude Oil ..................     --           --        --           --           1          1.0
  Dry holes(a) ...............      1          0.5         1          1.0          --           --
DEVELOPMENT:(b)
  Crude oil ..................     --           --        16         10.8          28         15.5
  Natural gas ................      3          3.0         3          1.5           1          1.0
  Dry holes ..................      2          1.5         2          2.0           4          3.2
  Service wells ..............     --           --         1          0.5           8          5.5
                                   --          ---        --         ----          --         ----

     Total ...................      6          5.0        23         15.8          42         26.2
                                   ==          ===        ==         ====          ==         ====
</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, 2001, we were not drilling any wells.

RESERVES

      The following table summarizes our net proved crude oil and natural gas
reserves as of December 31, 2001, 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



                                       15
<PAGE>




and natural gas reserves located in Texas which have been audited, depending on
location, by the independent engineers named in the preceding sentence.

<Table>
<Caption>

                                                       AS OF DECEMBER 31, 2001
                                      -------------------------------------------------------------
                                         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                               2,980           5,400           3,880       $  19,377
   Cox Penn                              3,050               0           3,050          15,199
   East Fitts                           22,579             905          22,730          72,030
   East Velma Middle Block              10,276           2,160          10,636          48,917
   Eola                                  3,892           3,455           4,468          29,678
   North Alma Deese                      7,716               0           7,716          25,972
   Sholem Alechem                        5,046           2,682           5,493          21,830
   Tatums                                3,869              11           3,871          19,688
   Other Oklahoma - operated             1,801              92           1,816           6,788
   Other Oklahoma - non-operated         1,297           4,525           2,051           8,614
                                        ------          ------          ------       ---------
      Total Oklahoma Properties         62,506          19,230          65,711         268,093
                                        ------          ------          ------       ---------

MISSISSIPPI PROPERTIES:
   Brookhaven                            4,076               0           4,076          20,487
   Laurel                                8,524               0           8,522          19,948
   Martinville                           3,095               0           3,095          12,937
   Soso                                  3,735               0           3,735          14,595
   Summerland                            2,624               0           2,624           4,703
   Other Mississippi                     1,247           1,132           1,436           6,577
                                        ------          ------          ------       ---------
      Total Mississippi Properties      23,301           1,132          23,488          79,247
                                        ------          ------          ------       ---------

   Other Texas Properties                1,334             305           1,385           5,105
                                        ------          ------          ------       ---------
TOTAL                                   87,141          20,667          90,584       $ 352,445
                                        ======          ======          ======       =========
</Table>


     At December 31, 2001, we had net proved developed reserves of 63,757 MBOE
and net proved undeveloped reserves of 26,827 MBOE. The present value of proved
reserves of $352.5 million represented $255.7 million for the proved developed
reserves and $96.8 million for the proved undeveloped reserves. The present
value of proved reserves is based on year end market prices of $19.84 per barrel
for crude oil and $2.57 per MMbtu for natural gas. Market prices for crude oil
and natural gas have fluctuated significantly over the last three years. At
December 31, 2000, we reported total proved reserves of 100,778 MBOE, and the
present value of proved reserves was $756.6 million with year end crude oil and
natural gas prices of $26.80 per barrel and $9.78 per MMbtu, respectively.

     Reserves volumes and values declined from 2000 to 2001 primarily due to
lower crude oil and natural gas prices used to prepare the 2001 year-end
reserves as compared to the 2000 year-end reserves. Reserves produced during
2001 and downward revisions in reserve estimates also contributed to the decline
in reserves. Following are the major changes in reserves due to price declines
and downward revisions.

     o    We estimate that the change in reserves from the difference in crude
          oil and natural gas prices between December 31, 2000 and December 31,
          2001 represents a decrease of approximately 5.7 MMBOE to our net
          proved reserves and a related decrease of approximately $375.9 million
          in net present value of proved reserves.

     o    The net 2,763 MMcf (453 MBOE) of natural gas reserves associated with
          North Padre Island field located in Federal waters, offshore Texas
          were removed from proved reserves during 2001 due to the lack of
          success in attempts to workover the well in 2001.

     o    The drilling of the BFU 32N-15 Well No. 1 in the Brookhaven field to
          develop proved undeveloped reserves was unsuccessful due to the
          producing reservoir being encountered structurally low to prognosis.



                                       16
<PAGE>

          The re-interpretation of the productive area of this producing
          reservoir has led us to remove four proved undeveloped locations from
          our net proved reserves totaling approximately 896 MBOE.

     o    The poor drilling results on the two Cotton Valley wells in the Soso
          Field and the lack of success in encountering commercial production in
          the targeted Hosston interval in one of these Cotton Valley wells
          resulted in downward revisions in reserves of 698 MBOE.

     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 proved and unproved 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
16 to our consolidated financial statements included in this Form 10-K.



                                       17
<PAGE>

ACREAGE

     The following table summarizes the developed and undeveloped acreage we
owned or leased at December 31, 2001:

<Table>
<Caption>

                                         Developed              Undeveloped
                                  ----------------------    --------------------
                                    Gross         Net         Gross        Net
                                  ---------    ---------    ---------    -------
<S>                               <C>          <C>          <C>          <C>
Mississippi ..................     24,246       22,989       14,046       10,394
Oklahoma .....................     38,783       29,520        4,079        1,986
Texas ........................      4,860        3,678        1,296        1,134
Offshore Gulf of Mexico ......      5,760        2,269           --           --
                                   ------       ------       ------       ------

          Total ..............     73,649       58,456       19,421       13,514
                                   ======       ======       ======       ======
</Table>

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 under our cash collateral order 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 Mississippi crude oil is sold under contracts
which are based on posted crude oil prices and substantially all of our Oklahoma
crude oil is sold under contracts which are based on the New York Mercantile
Exchange price. In some circumstances, natural gas liquids are removed from our
natural gas production and are sold by us at posted prices. During 2001, EOTT
Energy Operating Limited Partnership, TEPPCO Crude Oil, L.P. and Sunoco, Inc.
accounted for 41%, 30% and 13%, respectively, of our revenues. 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




                                       18
<PAGE>

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.

     The general partner of EOTT Energy Operating Limited Partnership is a
wholly-owned subsidiary of Enron Corp. Each month we are requesting a letter of
credit from EOTT for the purchase of our future month production to minimize
credit risk that may exist due to their affiliation with Enron Corp. If we do
not receive these letters of credit, any adverse developments relating to Enron
Corp. that may have an adverse effect on EOTT may in turn impact EOTT's ability
to fulfill its obligations to us.

     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. This contract was extended to continue on a month-to-month basis during
2002 by mutual agreement of both parties. During 1999, we entered into a
separate contract with EOTT to sell approximately 50% of our heavy Mississippi
crude oil through December 31, 1999. This contract continues annually until
terminated by either party and contains similar pricing arrangements based on
postings plus a premium with an adjustment for gravity and sets a minimum
wellhead 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, 2002. Pursuant to a
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. During 2001, Amoco
did not exercise their right to bid on our crude oil.

     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 markets, 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 operating income 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. Effective January 1, 2002, we
dedesignated the hedging relationship for the remainder of our hedges.
Accordingly, all future unrealized gains and losses on our derivatives will be
recognized through earnings. 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;



                                       19
<PAGE>

     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;

     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 affects 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.




                                       20
<PAGE>





     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;

     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 and
          nonhazardous wastes; 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, as amended by the
Superfund Amendments and Reauthorization Act, and the Resource Conservation and
Recovery Act. We hold all the necessary permits for our operations and to the
best of our knowledge are not the subject of any environmental investigation.
Management believes compliance with environmental 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 also continue to be
involved in 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 "NORM". NORM is present in varying concentrations in both surface and
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



                                       21
<PAGE>

concentrations of NORM above prescribed levels because of crude oil and natural
gas production activities. We will be continuing our voluntary NORM remediation
projects at several fields in Mississippi.

EMPLOYEES

     At March 1, 2002, we had 72 employees associated with our operations,
including 20 field personnel in Mississippi and 22 field personnel in Oklahoma.
None of our employees is represented by a union. We consider our employee
relations to be satisfactory.

RISK FACTORS RELATED TO OUR BUSINESS

WE HAVE FILED FOR BANKRUPTCY AND IT MAY NOT BE POSSIBLE FOR US TO CONTINUE AS A
GOING CONCERN AND YOU MAY NOT RECEIVE ANY CASH IF WE LIQUIDATE ALL OF OUR
ASSETS.

     On February 6, 2002, we and our wholly subsidiaries, Coho Resources, Inc.
and Coho Oil & Gas, Inc., filed a voluntary petition for relief under Chapter 11
of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the
Northern District of Texas. The bankruptcy petitions were filed to protect us
while we develop a solution to our liquidity problems. We are currently
operating as debtor-in-possession under the court's supervision and pursuant to
its orders. We have agreed with the lenders under the senior credit facility to
develop a marketing plan with our new financial advisor, CIBC, for the sale of
our assets or a recapitalization of our debt and equity. Any sale or
recapitalization will be subject to bankruptcy court approval under a Chapter 11
plan of reorganization or liquidation or in accordance with Section 363 of the
bankruptcy code, which generally provides for a partial sale of assets prior to
confirmation of a plan of reorganization or liquidation.

     At this time, it is not possible to predict the outcome of the bankruptcy
proceedings, in general, or the effect of the bankruptcy on our business or on
the interests of the creditors or shareholders. We believe, however, that it may
not be possible to satisfy in full all of the claims against us. In addition,
the shareholders of our company may not realize any value on their investment.

THE BANKRUPTCY MAY HAVE CREATED A NEGATIVE IMAGE OF US.

     We cannot predict whether our bankruptcy filing will have a negative
effect, if any, on our operations. Although we believe that the bankruptcy
filing has had and will continue to have a minimal effect on our relationships
with our customers, employees and suppliers, we cannot assure you that there
will not be a detrimental impact on future sales and patronage because of the
negative image of us that may have been created by the bankruptcy.

LIQUIDITY AND COURT IMPOSED CONSTRAINTS MAY HINDER OUR CONTINUED OIL AND GAS
OPERATIONS.

     Since filing for bankruptcy protection on February 6, 2002, we have been
operating under the constraints of a cash collateral order and we are subject to
expenditure constraints imposed by the bankruptcy court.

     Our only sources of liquidity during the pendency of the bankruptcy
proceeding will be cash on hand and cash generated by operations.

PAST SUBSTANTIAL NET LOSSES MAY AFFECT FUTURE OPERATIONS.

     We experienced substantial net losses for the years ended December 31, 1999
and 2000 of $30.7 million and $32.7 million, respectively. For the year ended
December 31, 2001, we experienced a loss before accumulated effect of an
accounting change of $4.4 million. If we continue as a going concern, we may not
become profitable in the future.

WE MAY NOT BE ABLE TO REPLACE DEPLETED RESERVES AT A LEVEL NECESSARY TO CONTINUE
OUR CURRENT PRODUCTION LEVEL.

     The rate of production from crude oil and natural gas properties declines
as reserves are depleted. Except to the extent we acquire additional properties
containing proved reserves, or conduct successful exploration and development
activities that identify additional formations with primary or secondary reserve
opportunities on our own properties, our proved reserves will decline as
reserves are produced. Future crude oil and natural gas production is therefore
highly dependent on our level of success in finding and acquiring additional
reserves. Our



                                       22
<PAGE>

ability to acquire producing properties assumes that major integrated oil
companies and independent oil companies will continue to divest some of their
crude oil and natural gas properties. These divestitures may not continue and we
may not be able to acquire producing properties at acceptable prices. Our
ability to develop or acquire additional reserves is limited due to the capital
constraints imposed by the bankruptcy court.

OUR HIGH LEVEL OF DEPENDENCE ON THREE MAIN CUSTOMERS MAY DIRECTLY AFFECT OUR
INCOME STATEMENT.

     During 2001, three purchasers of our crude oil and natural gas, EOTT Energy
Operating Limited Partnership, TEPPCO Crude Oil, L.P. and Sunoco, Inc. accounted
for 41%, 30% and 13%, respectively, of our revenues. While we believe that 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 effect our share price. In addition, any
significant late payment may adversely effect our short-term liquidity position.

     The general partner of EOTT Energy Operating Limited Partnership is a
wholly-owned subsidiary of Enron Corp. Each month we are requesting a letter of
credit from EOTT for the purchase of our future month production to minimize our
potential credit risk that may exist due to their affiliation with Enron Corp.
If we do not receive this letter of credit, any adverse developments relating to
Enron Corp. that may have an adverse effect on EOTT may in turn impact EOTT's
ability to fulfill its obligation to us.

IF WE ARE UNABLE TO COMPETE EFFECTIVELY AGAINST MAJOR OIL COMPANIES AND OTHER
INDEPENDENT OPERATORS, WE MAY BE UNABLE TO OBTAIN NECESSARY MATERIALS AND
RESOURCES AND MAY EXPERIENCE A SIGNIFICANT DISRUPTION OF OUR OPERATIONS.

     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 underdeveloped crude oil and
natural gas properties. Many of our competitors have financial resources, staff
and facilities substantially greater than ours. Although we believe the current
operating resources available under our cash collateral order 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.


                                       23
<PAGE>

OUR COMMON STOCK IS NOT LISTED ON THE NASDAQ NATIONAL MARKET OR ANY OTHER STOCK
EXCHANGE, WHICH MAY DEPRESS THE PRICE OF THE COMMON STOCK AND YOU MAY HAVE
DIFFICULTIES RESELLING THE STOCK.

     Our common stock is not listed on the Nasdaq National Market or any other
national securities exchange which may affect the liquidity and marketability of
our common stock.

OUR PROFITABILITY IS HIGHLY DEPENDENT ON INDUSTRY CONDITIONS THAT HAVE, IN THE
PAST, CAUSED US TO IMPLEMENT SIGNIFICANT WRITE-DOWNS OF OUR ASSETS.

     Our revenue, profitability and future rate of growth substantially depend
on prevailing prices for crude oil and natural gas. Crude oil and natural gas
prices can be extremely volatile. Prices are also affected by actions of state
and local agencies, the United States and foreign governments and international
cartels.

IF OIL PRICES DECLINE SIGNIFICANTLY, WE MAY HAVE TO WRITE DOWN THE CARRYING
VALUE OF OUR RESERVES.

     We periodically review the carrying value of our crude oil and natural gas
properties under the full cost accounting rules of the Securities and Exchange
Commission. Under these rules, a ceiling test is performed whereby capitalized
costs of proved oil and natural gas properties may not exceed a present value,
based on unescalated prices at a single point in time, of estimated future net
revenues from proved reserves, discounted at 10%. Application of the ceiling
test generally requires pricing future revenue at the unescalated prices in
effect as of the end of each fiscal quarter and requires a write-down for
accounting purposes if the ceiling is exceeded. When a write-down is required,
it results in a charge to earnings, but does not affect cash flow from operating
activities. Once incurred, a write-down of crude oil and natural gas properties
is not reversible at a later date.

OUR ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUE INFORMATION MAY DIFFER
FROM ACTUAL RESULTS WHICH COULD AFFECT OUR REPORTED ASSETS AND OUR ABILITY TO
BORROW FUNDS.

     There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond our control. The reserve
data included in our 2001 annual report on Form 10-K represent only estimates.
In addition, the estimates of future net revenue from proved reserves and their
present value are based on assumptions about future production levels, prices
and costs that may change over time. In particular, estimates of crude oil and
natural gas reserves, future net revenue from proved reserves and the present
value of proved reserves for the crude oil and natural gas properties described
in our 2001 annual report are based on the assumption that future crude oil and
natural gas prices remain the same as crude oil and natural gas prices at
December 31, 2001. The New York Mercantile Exchange prices as of December 31,
2001, used for purposes of our estimates were $19.84 per Bbl of crude and $2.57
per MMbtu of natural gas, respectively. Any significant variance in actual
results from these assumptions we use could also materially affect the estimated
quantity and value of our reserves.

COSTS OF ENVIRONMENTAL LIABILITIES, REGULATION AND LITIGATION COULD EXCEED OUR
ESTIMATES.

     Our current and former operations involve management of regulated materials
and are subject to various environmental laws and regulations. These laws and
regulations may obligate us to remediate various sites at which petroleum,
chemicals, low-level radioactive substances or other regulated materials may
have been disposed of or released. We have been party to legal proceedings
involving environmental matters in the past. Although these legal proceedings
were settled in connection with our plan of reorganization, there can be no
assurance that we will not be party to other legal proceedings involving
environmental matters in the future.

     It is not possible for us to estimate reliably the amount and timing of all
future expenditures related to environmental matters because of:

     o    the difficulty of estimating remediation costs;

     o    the uncertainty in quantifying liabilities under environmental laws
          that may impose joint and several liability on all potentially
          responsible parties; and



                                       24
<PAGE>

     o    the nature of environmental laws and regulations.

     Although we believe we have established appropriate reserves for
liabilities, including remediation costs, we could be required to set aside
additional reserves in the future due to these uncertainties.

ITEM 3. LEGAL PROCEEDINGS

Bankruptcy Proceedings. On February 6, 2002, we and our consolidated
subsidiaries, Coho Resources, Inc. and Coho Oil & Gas, Inc., filed a voluntary
Chapter 11 petition in the United States Bankruptcy Court for the Northern
District of Texas. Consistent with bankruptcy cases involving publicly traded
companies and their affiliates, a number of proceedings have occurred since
February 6, 2002, the most significant of which are discussed below.

     The bankruptcy court approved Fulbright & Jaworski L.L.P. as our counsel,
CIBC World Markets Corp. as our financial advisor and Arthur Andersen LLP as our
auditors for the year ended December 31, 2001. The bankruptcy court also
approved our retention of ordinary course of business professionals. These
professionals are assisting us in our efforts to reorganize our business and to
continue our operations as debtor-in-possession.

     An official committee for the unsecured creditors has been formed by the
Office of the United States Trustee. The bankruptcy court approved counsel for
the Official Unsecured Creditors Committee.

     The bankruptcy court approved our use of cash collateral in the continued
operations of our business, including its use in our capital expenditure
programs. Our use of cash collateral has been approved through April 30, 2002. A
budget for the next two month period (May and June 2002) will be submitted by
April 1, 2002 for approval in April 2002. In February and March 2002, under the
Order Authorizing Use Of Cash Collateral, we paid the bank group interest
payments of $2.5 million and $823,000, respectively. We plan on making
additional interest payments on a monthly basis.

     Immediately following the commencement of our bankruptcy case, we obtained
permission from the bankruptcy court to pay working and royalty interest owners
to ensure that payments to them were not interrupted. As a result, working and
royalty interest owners will continue to receive all payments to which they are
entitled throughout the pendency of our bankruptcy cases.

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 on May 27, 1999. 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. We
reached a settlement of the litigation in May 2001, subject to approval of the
United States Bankruptcy Court (the "Bankruptcy Court") and resolution of
certain disputes relating to a matter under seal by order of the Bankruptcy
Court as discussed below. Final settlement documents were signed during October
2001 and approved by the Bankruptcy Court in January 2002. The disputed
termination issue discussed below has not been finalized so the final settlement
has been extended until April 15, 2002. We do not expect the settlement to have
a material impact on our financial position or results of operations.

     Pursuant to our 2000 plan of reorganization, shareholders as of February 7,
2000, are eligible to receive their pro rata share of 20% of the proceeds
available from the Hicks Muse lawsuit settlement after fees and expenses. We
have not yet determined the impact, if any, of our current bankruptcy
proceedings on the distribution of these proceeds to shareholders.

     During 2001, we became involved in a matter in connection with the lawsuit
filed by us against Hicks Muse. This matter is under seal by order of the
Bankruptcy Court. The matter involves a termination issue and the plaintiff
claims damages that are based on a percentage of the ultimate amount recovered,
if any, in the lawsuit against Hicks Muse. These percentages would be calculated
on a graduated scale decreasing from 30% to 10% as the amount recovered
increases. Alternatively, the plaintiff claims damages on the basis of lost
time. However, we do not believe that either of these methods represents an
appropriate measure of damages. We believe the claim is without merit. At the
order of the Bankruptcy Court, certain matters were arbitrated. The arbitration
panel's sealed findings



                                       25
<PAGE>

were forwarded to the Bankruptcy Court for consideration in conjunction with the
final settlement discussed above. The damages awarded are currently being
appealed by us and the plaintiff. We do not expect this matter to have a
material impact on our financial position or results of operations. Resolution
of this matter may, however, impact the amount of proceeds available to us from
the settlement of the Hicks Muse lawsuit.

     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
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. Subsequently, the plaintiff
named Ryder Scott Company and Sproule Associates Inc., the independent petroleum
consultants which evaluate our oil and gas reserves, as additional defendants.
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
settlement of our lawsuit against certain affiliates of Hicks, Muse, Tate &
Furst, as described above, requires dismissal of the claims against the former
officers. If the suit continues against Ryder Scott Company and Sproule
Associates Inc., we may be required to indemnify these companies subject to the
terms contained in our agreements with them; however, we do not expect the
ultimate outcome of this matter to have a material impact on our financial
position or results of operations.


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

     None.




                                       26
<PAGE>

                                     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. As a
result of our recent filing of a voluntary petition for bankruptcy protection,
the trading value of our common stock on March 28, 2002 was $.01.

<Table>
<Caption>

                                                   HIGH               LOW
                                                 -------            --------
<S>               <C>                            <C>                <C>
2000
                  1st Quarter                    $   .75            $    .20
                  2nd Quarter                      12.00                2.00
                  3rd Quarter                       8.25                6.00
                  4th Quarter                       6.75                2.88
2001
                  1st Quarter                    $  5.13            $   2.75
                  2nd Quarter                       7.20                4.81
                  3rd Quarter                       6.05                 .75
                  4th Quarter                       1.05                 .01
</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
March 25, 2002, there were 203 holders of record of our common stock.

     Prior to March 31, 2000, the effective date of the 2000 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
currently do not anticipate being able to pay cash dividends in the foreseeable
future in light of our bankruptcy filing. 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. 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.



                                       27
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA

     The following selected consolidated financial data for each of the five
years in the period ended December 31, 2001 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,
                                                         -----------------------------------------------------------------
                                                           1997          1998           1999         2000           2001
                                                         ---------     ---------     ---------     ---------     ---------
                                                                 (IN THOUSANDS, EXCEPT EARNINGS PER SHARE AMOUNTS)
<S>                                                      <C>           <C>           <C>           <C>           <C>
STATEMENT OF OPERATIONS DATA:
    Operating revenues ..............................    $  63,130     $  68,759     $  57,323     $  90,182     $  76,956
    Operating costs .................................       15,970        26,859        21,155        29,320        29,994
    General and administrative expenses .............        7,163         7,750         9,905         7,137         5,416
    Reorganization costs ............................           --            --         3,123        12,004        (3,238)
    Depletion and depreciation ......................       19,214        28,135        13,702        15,316        17,811
    Writedown of crude oil and natural gas
          properties ................................           --       188,000         5,433         3,027            --
    Net interest expense(a) .........................       10,474        32,721        33,698        50,907        31,070
    Income tax expense (benefit) ....................        4,021       (14,383)          (26)           --            --
    Accumulated effect of an accounting
          change(e)..................................           --            --            --            --         9,180
    Income (loss) before extraordinary items ........        6,288      (203,346)      (30,715)      (28,294)        4,806
    Net income (loss) ...............................        6,288      (203,346)      (30,715)      (32,722)        4,806
    Basic income (loss) before extraordinary
          items per common share(b) .................    $    1.16     $ (317.68)    $  (47.99)        (1.98)          .26
    Basic income (loss) per common share(b) .........    $    1.16     $ (317.68)    $  (47.99)        (2.29)          .26
    Diluted income (loss) before extra-
          ordinary items per common share(c) .........   $    1.13     $ (317.68)    $  (47.99)        (1.98)          .26
    Diluted income (loss) per common share(c) .......    $    1.13     $ (317.68)    $  (47.99)        (2.29)          .26
OTHER FINANCIAL DATA:
    Capital expenditures ............................    $  72,667     $  70,143     $   6,349     $  25,272     $  33,162
BALANCE SHEET DATA:
     Working capital (deficit)(d) ...................    $  (2,021)    $(388,297)    $(407,490)    $  (2,647)    $(284,075)
     Net property and equipment .....................      531,409       324,574       311,788       317,667       332,952
     Total assets ...................................      555,128       350,068       348,801       366,791       377,143
     Long-term debt, excluding current portion ......      369,924            --            --       282,412         2,710
     Total shareholders' equity .....................      142,103       (61,243)      (91,958)       61,509        68,732
</Table>

(a)  Amounts for 2000 and 2001 include interest expense of $36,192 and $35,476,
     respectively, and loss (gain) on standby loan embedded derivative of
     $15,163 and $(4,130), respectively, partially offset by interest income of
     $(448) and $(276), respectively.

(b)  Basic per share amounts have been computed by dividing net earnings after
     preferred dividends by the weighted average number of shares outstanding:
     542 in 1997; 640 in 1998; 640 in 1999; 14,266 in 2000; and 18,714 in 2001.

(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: 558 in 1997; 640 in 1998; 640 in
     1999; 14,266 in 2000; and 18,714 in 2001.

(d)  Amounts for 1998, 1999 and 2001 include $384,031, $388,685 and $282,845
     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 our 1999 bankruptcy filing.

(e)  Accumulated effect of an accounting change for 2001 relates to the adoption
     of SFAS No. 133 "Accounting for Derivative Instruments and Hedging
     Activities." See "Managements Discussion and Analysis of Financial
     Condition and Results of Operations - Results of Operations" for a
     discussion on accounting change.



                                       28
<PAGE>




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 have carried a high level of indebtedness since we reorganized and
emerged from bankruptcy on March 31, 2000. Our total consolidated indebtedness
is $308.0 million and our ratio of total consolidated indebtedness to total
capitalization was 82% as of December 31, 2001. Our major borrowings are
comprised of $195 million under a senior revolving bank credit facility and
$93.5 million under senior subordinated notes due 2007 that were issued mainly
to our majority shareholders and herein referred to as the standby loan.
Interest owned under our standby loan is currently required to be "paid-in-kind"
by increasing the amount of the principal outstanding through the issuance of
additional standby notes.

     In April 2001, we entered into an agreement with JP Morgan, a division of
Chase Securities, to act as our financial advisor in evaluating various
strategic transactions including potential recapitalization transactions or the
sale of all or a portion of our company.

     Although we entered into negotiations with a third party for the sale of
our Mississippi oil and gas assets in September and October 2001, we were not
able to complete the sale.

     On November 1, 2001, the lenders under our senior revolving bank credit
facility notified us that our borrowing base under this facility had been
reduced from $195 million to $175 million effective November 1, 2001. On
November 2, 2001, we received a notice of borrowing base deficiency because
borrowings under the credit facility exceeded the redetermined borrowing base by
$20 million. Under the credit facility, we could have remedied the borrowing
base deficiency by providing additional collateral sufficient to eliminate the
borrowing base deficiency or by making a cash payment sufficient to eliminate
the borrowing base deficiency. Currently, all of our assets are pledged as
collateral under the credit facility and we did not have sufficient working
capital to make a cash payment to eliminate the borrowing base deficiency within
the 90 day cure period. On February 1, 2002, we received a notice of default
under the credit facility and subsequently filed a voluntary petition for relief
under Chapter 11 of the U.S. Bankruptcy Code as discussed below.

SUBSEQUENT EVENT - BANKRUPTCY PROCEEDINGS

     On February 6, 2002, we and our wholly owned subsidiaries, Coho Resources,
Inc. and Coho Oil & Gas, Inc., filed a voluntary petition for relief under
Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for
the Northern District of Texas. The bankruptcy petitions were filed to protect
us while we develop a solution to our liquidity problems. We are currently
operating as debtor-in-possession under the court's supervision and pursuant to
its orders. We filed schedules with the bankruptcy court on March 8, 2002. Those
schedules contain our unaudited, and in some cases, estimated assets and
liabilities as of February 6, 2002, as shown by our accounting records.

     Under our cash collateral order, we have agreed with the lenders under the
senior credit facility to develop a marketing plan with our new financial
advisor, CIBC, for the sale of our assets or a recapitalization of our debt and
equity. We, together with CIBC, are currently working with our bank group and
the unsecured creditors committee on mutually acceptable terms for this
marketing plan to achieve maximum value for our assets in this process. We
expect that once finalized and approved, the marketing plan will allow us to
explore other alternatives available to us, in addition to a sale of our assets,
including a recapitalization of our debt and equity assuming we are able to
raise sufficient equity from existing or new investors to cure the $20 million
borrowing base deficiency and to provide working capital to develop our
properties. A recapitalization may include a partial sale of our assets. Any
sale or recapitalization will be subject to bankruptcy court approval under a
Chapter 11 plan of reorganization or liquidation or in accordance with Section
363 of the bankruptcy code.


                                       29
<PAGE>

     At this time, it is not possible to predict the outcome of the bankruptcy
proceedings, in general, or the effect on our business or on the interests of
the creditors or shareholders. We believe, however, that it may not be possible
to satisfy in full all of the claims against us. In addition, the shareholders
of our company may not realize any value on their investment. As a result of the
bankruptcy filing, all of our liabilities incurred prior to February 6, 2002,
including secured debt, are subject to compromise. Under the bankruptcy code,
payment of these liabilities may not be made except pursuant to a plan of
reorganization or liquidation or bankruptcy court approval.

     No adjustments to the carrying value of our assets or liabilities related
to the bankruptcy filing have been reflected in our December 31, 2001 balance
sheet. In accordance with SOP 90-07, "Financial Reporting by Entities in
Reorganization Under the Bankruptcy Code", during 2002, we will adjust
liabilities subject to compromise to our estimate of the allowed claims.
Accordingly, during 2002, we will write-off unamortized debt issuance costs and
debt discounts of $22.6 million and $10.7 million, respectively. These
adjustments to the December 31, 2001, carrying values will be recorded in
earnings as reorganization items. In addition, we will record the prepayment
penalty ($30.8 million at December 31, 2001) and adjust the recorded amount of
the standby loan embedded derivative, based on the estimated allowed claims
during 2002.

     Subsequent to February 6, 2002, we filed two motions with the bankruptcy
court to seek use of the bank group's cash collateral on an on-going basis.
Since filing bankruptcy, we have been operating under two orders authorizing the
use of cash collateral, initially an interim order and currently a final order
which was approved on February 26, 2002 and authorizes expenditures through
April 30, 2002. Under these orders, we may pay for ordinary course of business
goods and services incurred after February 6, 2002 that are within the court
approved budgets attached to each order. Any expenditure that is outside the
ordinary course of business or that is not reflected in the approved budgets
must be specifically approved by the bankruptcy court.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     Our discussion and analysis of our financial condition and results of
operation are based upon our consolidated financial statements, which have been
prepared in accordance with generally accepted accounting principles as
presently established in the United States. The preparation of these financial
statements requires us to make estimates and judgments that affect the reported
amounts of assets, liabilities, equity, revenues and expenses. We prepare our
estimates, including those related to oil and gas revenues, bad debts, oil and
gas properties, crude oil and natural gas reserves, embedded derivative fair
values, contingencies and litigation. We base our estimates on historical
experience and various other assumptions that are believed to be reasonable
under the circumstances. Actual results may differ from these estimates under
different assumptions or conditions. We believe our more significant judgments
and estimates affect the following critical accounting policies used in the
preparation of our consolidated financial statements. See Note 1 to the
Consolidated Financial Statements for a complete list of significant accounting
policies.

     Crude Oil and Natural Gas Properties. 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.

     Management's assumptions used in calculating oil and natural gas reserves
or regarding the future cash flows or fair value of our properties are subject
to change in the future. Any change could cause impairment expense to be
recorded, reducing our net income and our basis in the related asset. Future
prices received for production and future production costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of calculating
reserve estimates. There can be no assurance that the proved reserves will be
developed within the periods estimated or that prices and costs will remain
constant. Actual production may not equal the estimated amounts used in the
preparation of reserve projections. As these estimates change, the amount of
calculated reserves change.



                                       30
<PAGE>

     Depletion and depreciation expense is also directly affected by our reserve
estimates. Any change in reserves directly impacts the amount of depletion and
depreciation expense we recognize in a given period. Assuming no other changes,
such as an increase in depreciable base, as our reserves increase, the amount of
depletion and depreciation expense in a given period decreases and vice versa.
Changes in future commodity prices would likely result in increases or decreases
in estimated recoverable reserves.

     Bad Debt Expense. We routinely assess the recoverability of all material
trade and other receivables to determine their collectibility. Many of our
receivables are from joint interest owners on property of which we are the
operator. Thus, we may have the ability to withhold future revenue disbursements
to cover any non-payment of joint interest billings. Our crude oil and natural
gas receivables quickly turnover, usually one month for oil and two months for
gas; thus, signaling any problem accounts in a timely manner. This review of
receivables is dependent on the judgment of management. If it is determined that
the carrying value of a receivable might not be recoverable, we record an
allowance to the extent we believe the receivable is not recoverable.

     Embedded Derivatives. We adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" effective January 1, 2001, as more fully
discussed under "Hedging Activities and Other Derivatives." SFAS 133 requires us
to recognize all derivative instruments (including embedded derivatives) on the
balance sheet at fair value. We estimate the fair value of the embedded
derivatives contained in our standby loan agreement and certain lease agreements
based on future crude oil and natural gas price curves, historical crude oil and
natural gas volatility and estimated discount rates. Actual future prices may
not equal the estimated amounts and significant fluctuations in earnings could
result as prices increase or decrease from the price estimates used in
estimating the fair value of these embedded derivatives. During 2002, subsequent
to our bankruptcy filing, we will adjust the recorded amount of the standby loan
embedded derivative based on the estimated allowed claim as previously discussed
under "Subsequent Event - Bankruptcy Proceedings."

     Revenue Recognition Policy. We recognize revenue from the sale of crude oil
and natural gas in the period delivered.

LIQUIDITY AND CAPITAL RESOURCES

     Capital Sources. During 2001, cash flow provided by operating activities
was $24.4 million compared with $9.9 million for the same period in 2000.
Operating revenues, net of lease operating expenses, production taxes and
general and administrative expenses, decreased $12.2 million from $53.7 million
in 2000 to $41.5 million in 2001, primarily due to:

     o    realized crude oil price decreases of 17% between such comparable
          periods;

     o    decreases in natural gas production; and

     o    increases in operating expenses.

These decreases were partially offset by:

     o    increases in crude oil production;

     o    decreases in production taxes; and

     o    decreases in general and administrative expenses.

Cash flow provided by operating activities also included $10.9 million in
reorganization costs (excluding a $1.1 million Tunisian impairment) in 2000 and
$21.4 million in interest expense on our old and new bank credit facilities in
2000 as compared to a reduction of $3.2 million in reorganization costs and
$14.8 million in interest expense on our credit facility during 2001. Changes in
operating assets and liabilities resulted in $4.6 million of cash used for
operating activities for 2001, compared to $11.7 million of cash used for
operating activities for the same period in 2000. See "Results of Operations"
for a discussion of operating results.



                                       31
<PAGE>
     Working Capital. We had a working capital deficit of $284.1 million at
December 31, 2001 compared to a working capital deficit of $2.6 million at
December 31, 2000. The decrease in working capital primarily relates to an
increase of $281.8 million in current portion of long term debt and an increase
of $11.8 million in accrued unrealized losses on embedded derivatives due to our
default under our senior revolving credit facility in February 2002 and a
decrease of $3.3 million in accounts receivable. These decreases in working
capital are partially offset by several factors including the following:

     o    an increase of $2.1 million in cash and cash in escrow;

     o    an increase of $2.4 million in other current assets, primarily related
          to accrued unrealized gains on derivatives due to the adoption of
          SFAS. No. 133;

     o    a decrease of $3.1 million in accrued operating costs;

     o    a decrease of $2.7 million in accrued interest payable;

     o    a decrease of $2.0 million in accrued reorganization costs;

     o    a decrease of $1.1 million related to environmental claims;

     o    a decrease of $895,000 in accrued hedging losses;

     o    a decrease of $415,000 in trade payables; and

     o    a decrease of $690,000 in various other accrued liabilities.

     Credit Facilities. We, and some of our subsidiaries, were parties to an old
bank group loan agreement prior to March 31, 2000. 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.

     The existing senior revolving credit facility was obtained from a syndicate
of lenders led by JPMorgan Chase Bank, as agent for the lenders, and has a
maximum loan commitment amount of up to $250 million through March 31, 2003. The
credit facility limits advances to the amount of the borrowing base, which 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. We, or Chase, may each request one additional
borrowing base redetermination during any calendar year. The April 1, 2001
redetermination resulted in a decrease in our borrowing base from $205 million
to $195 million. As discussed more fully under "General", on November 1, 2001,
the lenders under the senior revolving credit facility notified us that our
borrowing base under this facility had been redetermined in the semiannual
review from $195 million to $175 million effective November 1, 2001. We were
unable to cure the $20 million borrowing base deficiency within the 90 day cure
period and we received a notice of default under the facility on February 1,
2002. At December 31, 2001, the outstanding advances of $195 million under the
senior revolving credit facility were classified as a current liability due to
the default under the credit facility.

     Interest on advances under the credit facility are payable on the earlier
of the expiration of any interest period under the credit facility or quarterly.
Amounts outstanding under the credit facility 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



                                       32
<PAGE>

from time to time as its prime rate of interest plus an applicable margin
(currently 2%). In the event any principal is not paid when due, whether at
maturity or upon acceleration, interest will accrue at the applicable rate, as
discussed above, plus 2%. Subsequent to filing a voluntary petition for
protection under the bankruptcy code on February 6, 2002, we have been operating
under a cash collateral order. Pursuant to the cash collateral order, interest
will accrue at the LIBOR rate plus the applicable margin (currently 3%) plus the
2% default rate until March 15, 2002 on borrowings of $20 million and until May
13, 2002 on borrowings of $175 million. Subsequent to these periods interest
will accrue at prime plus the applicable margin (currently 2%) plus the 2%
default rate.

The 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 credit agreement contains financial and other covenants including:

     o    maintenance of required ratios of cash flow to interest expense paid
          or payable in cash (not less than 2.75 to 1 for the average of the
          last four consecutive quarters most recently ended December 31, 2001;
          and 3.0 to 1 for the average of the last four quarters for any quarter
          ending after January 1, 2002), senior debt to cash flow required (not
          to exceed 3.75 to 1 for the average of the last four quarters most
          recently ended December 31, 2001; and 3.5 to 1 for the average of the
          last four consecutive quarters 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 not less than 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.

We were unable to maintain the required ratio of senior debt to cash flow and
current assets to current liabilities, as required by the credit agreement
during the fourth quarter of 2001. We believe that we were in compliance with
all other covenants under the credit facility at the end of the fourth quarter
of 2001. As of December 31, 2001, the covenant ratios of cash flow to interest
expense, senior debt to cash flow, and current assets to current liabilities
were 2.79 to 1, 4.7 to 1, and .06 to 1, respectively. Non-cash transactions
resulting from the adoption and accounting treatment of SFAS No. 133 are
excluded from the calculation of covenant ratios under the credit facility. As
previously discussed, as of February 1, 2002, we are in default under the credit
agreement. Accordingly, the entire balance outstanding at December 31, 2001, has
been classified as a current liability.

     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, herein referred to as the
"standby loan". At December 31, 2001, an aggregate amount of $93.5 million in
senior subordinated notes was outstanding under the standby loan. Our rights and
responsibilities and those of the standby lenders are governed by a standby loan
agreement dated 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
are payable in an amount equal to 1/2% for every $0.25 that the "actual price"
(as described below) 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. Any time the average realized price exceeds
$20 per barrel of oil equivalent, we will have to pay the 10% maximum additional
interest. The "actual price" for


                                       33
<PAGE>

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
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.

     The semiannual interest payments under the standby loan are required to be
paid-in-kind subject to the requirements of the intercreditor arrangement
between the standby lenders and the lenders under the new credit agreement
unless we meet specified financial tests. "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 payments in
the amount of $5.8 million, due on March 30, 2001 were paid-in-kind and were
reflected at issuance as an increase in long term debt and long term derivative
liabilities of $4.4 million and $1.4 million, respectively. The standby loan
interest payments of $10.3 million, which were at the maximum rate of 25%, were
paid-in-kind when due on September 28, 2001, and were reflected at issuance as
an increase in long term debt and long term derivative liabilities of $8.3
million and $2.0 million, respectively. Previously, interest accruing on the
standby loan, subsequent to the previous semiannual interest payment was
reflected in long term debt until the next semiannual interest was paid in cash
or paid-in-kind; however, due to the default under the standby loan agreement,
as discussed below, accrued interest at December 31, 2001 was classified as a
current liability.

     Payment of the standby loan notes is expressly subordinate to payments in
full in cash of all obligations arising in connection with the 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
credit agreement also prohibits us from making any cash interest payments on the
standby loan indebtedness if the outstanding indebtedness under both the credit
facility and the standby loan exceeds 3.75 times EBITDA for the trailing four
quarters. We do not currently meet and have not met in the past the requirements
to make cash interest payments on the standby loan indebtedness.

     We may prepay, or may be required to repay, under certain circumstances,
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, 2001, the
prepayment fee for the then total outstanding principal amounts, using then
current treasury rates, was approximately $30.8 million, bringing the total
obligation under the standby loan, including the prepayment fee and accrued
interest, to approximately $127.9 million.

     The standby loan agreement contains certain covenants and cross default
provisions, including cross default provisions which automatically cause us to
be in default under the terms of the standby loan agreement in the event we are
in default under the senior revolving credit facility or in the event we seek
relief under any provision of the bankruptcy law. In the event of default, the
standby lenders may declare all amounts due under the standby loan agreement
immediately due, unless the default is due to bankruptcy proceedings, which will
automatically accelerate all amounts due, including principal, accrued interest
and the prepayment fee. On February 1, 2002, we received a notice of default
under the senior revolving credit facility. This default automatically caused us
to be in default under the standby loan agreement. On February 6, 2002, we filed
a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code
which automatically accelerated all amounts due, including the prepayment fee,
under the standby loan. Due to the default under the standby loan agreement, the
carrying value of our outstanding debt at December 31, 2001 was classified as a
current liability. The prepayment fee was not payable until we defaulted under
the standby loan agreement during February 2002; therefore, it has not been
recorded on our balance sheet as of December 31, 2001.

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




                                       34
<PAGE>
     Capital Expenditures. During 2001, we incurred capital expenditures of
$33.2 million compared with $25.3 million for the same period in 2000. We spent
approximately $17.0 million in our Mississippi fields and $16.2 million in our
Oklahoma fields during 2001. We drilled 35 wells, as listed below, and continued
our development efforts through recompletions and workovers on existing wells
and initiation or expansion of waterflood projects within the field. We also
participated in the drilling of seven gross wells (.2 net wells) that were
completed on two outside operated Oklahoma properties. Following are the wells
drilled during 2001:

<Table>

<S>                         <C>  <C>
     Mississippi Fields:
        Brookhaven          -    1 dry hole
        Cranfield           -    1 producing gas
        Martinville         -    2 producing oil
        Soso                -    2 producing oil

     Oklahoma Fields:
        Tatums              -    10 producing oil; 5 service wells; 1 dry hole
        East Fitts          -     3 producing oil; 1 suspended drilling
        Jennings-Deese      -     2 producing oil; 3 service wells
        Eola                -     3 producing oil; 1 dry hole
        Non-operated        -     7 producing oil
</Table>

A $12 million capital expenditures budget for the year 2002 has been approved by
our board of directors, which will be funded by working capital from operations.
As discussed in "Subsequent Event - Bankruptcy Proceedings", we have filed for
relief under Chapter 11 of the United States Bankruptcy Code and future capital
expenditures will be subject to expenditure constraints imposed by the
bankruptcy court. Subsequent to the bankruptcy filing, a Final Order Authorizing
Use of Cash Collateral has authorized capital expenditures of approximately $1.0
million per month through April 30, 2002, at which time we expect the cash
collateral order to be amended to approve a similar capital expenditure level
for future months. We have no material capital commitments related to our
operations and are consequently able to adjust the level of our expenditures
based on available cash flow.

     General and administrative costs associated with our exploration and
development activities of $960,000 were capitalized for 2000 compared with
$765,000 of capitalized costs for 2001. Due to the significantly reduced budget
for 2002, we expect to reduce the amount of capitalized G&A to $300,000 during
2002.

     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 by
entering into certain arrangements that fix a minimum and maximum price range
per barrel. We entered into these arrangements to reduce the downside risk
associated with potential crude oil and natural gas price declines by setting a
floor price for our future production based on the New York Mercantile Exchange
crude oil and natural gas prices. Due to working capital constraints, we entered
into the "costless collar" type of transactions because they do not require
upfront premiums. Additionally, our 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. The amount we receive or pay 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 NYMEX for the
contract period. The amount we receive or pay 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. Hedging activities do not affect the
actual price received for our crude oil and natural gas sold. Effective January
1, 2002, we dedesignated the hedging relationship for the remainder of our
hedges. Accordingly, all future unrealized gains and losses on our derivatives
will be recognized through earnings. Net unrealized gains of $2.0 million as of
December 31, 2001, which are included in other comprehensive income will be
recognized in earnings over the original hedge period.



                                       35
<PAGE>

     Based on fourth quarter 2001 production levels, 36% of our 2002 crude oil
production has been hedged as follows:

     Minimum and Maximum Crude Oil Price Arrangements.

     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.

     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.

     o    500 barrels per day for the period April 1, 2002 to December 31, 2002,
          with a minimum price of $22.50 and a maximum price of $26.45.

     o    500 barrels per day for the period April 1, 2002 to December 31, 2002,
          with a minimum price of $22.50 and a maximum price of $25.50.

     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.

     We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" effective January 1, 2001. The Statement required 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 are 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
are reclassified to earnings. Subsequent changes in fair value for the
ineffective portion of derivatives qualifying as hedges and for derivatives that
do not qualify as hedges are adjusted to fair value through earnings.

     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 and certain lease
agreements contain provisions for additional lease payments based on certain
crude oil prices. The additional interest feature of the standby loan agreement
and the additional lease payment feature of the lease agreements are considered
embedded derivatives under SFAS No. 133. These embedded derivatives were
recorded as liabilities based on fair value on January 1, 2001 and subsequent
changes in fair value are recorded through earnings.

     Discontinuation of Tunisian Operations. We decided to discontinue our
participation in the exploration of two Tunisia, North Africa permits due to
capital commitments during 2001 exceeding $7 million net to our interest. The
two subsidiaries, Coho Anaguid, Inc. and Coho International Limited, that own
these permits filed for protection under Chapter 11 of the United States
Bankruptcy Code on February 20, 2001. During May 2001, Coho International
entered into a settlement agreement with the other joint owners in the permit
area. Under this agreement, Coho International assigned its interest in the
Fejaj permit to the other joint owners in exchange for the assumption by the
other joint owners of Coho International's existing obligations and existing
payables under the permit. During July 2001, Coho Anaguid, Inc. entered into a
definitive agreement to sell all of its interest in the Anaguid permit to
Pioneer Natural Resources Company and the other joint owners in the permit area
for cash proceeds of approximately $200,000 and the assumption of Coho Anaguid's
obligations under the permit totaling in excess of $7 million. These sales
agreements have been approved by the United States Bankruptcy Court and the
Tunisian government. We converted the bankruptcy proceedings for Coho Anaguid
and Coho International from Chapter 11 reorganization proceedings to Chapter 7
liquidation proceedings during the first quarter of 2002 to wind


                                       36
<PAGE>


down these proceedings. We have not recorded the liabilities subject to
compromise for these subsidiaries in our consolidated balance sheet as of
December 31, 2001 because these liabilities are solely obligations of the
bankrupt subsidiaries and, furthermore, substantially all of the obligations of
these subsidiaries will be assumed under the sales agreements.

RESULTS OF OPERATIONS

     SELECTED OPERATING DATA

<Table>
<Caption>

                                                  1999           2000               2001
                                              ------------    ------------     ------------
<S>                                           <C>             <C>              <C>
PRODUCTION:
   Crude oil (Bbl/day) ...................           9,159           9,658           10,107
   Natural gas (Mcf/day) .................           7,146           5,702            4,427
   BOE (Bbl/day) .........................          10,350          10,608           10,845
AVERAGE CRUDE OIL SALES PRICES:
   Actual price received per Bbl .........    $      15.40    $      26.10     $      20.66
   Hedging loss per Bbl ..................            0.00           (2.79)           (1.41)
                                              ------------    ------------     ------------
   Net price received per Bbl ............    $      15.40    $      23.31     $      19.25
                                              ============    ============     ============
AVERAGE NATURAL GAS SALES PRICES:
   Actual price received per Mcf .........    $       2.24    $       3.99     $       4.38
   Hedging loss per Mcf ..................            0.00           (0.26)           (0.70)
                                              ------------    ------------     ------------
   Net price received per Mcf ............    $       2.24    $       3.73     $       3.68
                                              ============    ============     ============
PER BOE DATA:
   Production costs ......................    $       4.82    $       6.06     $       6.35
   Production taxes ......................             .78            1.49             1.22
   Depletion .............................            3.63            3.94             4.50
PRODUCTION REVENUES (IN THOUSANDS):
   Crude oil .............................    $     51,469    $     82,390     $     71,008
   Natural gas ...........................           5,854           7,792            5,948
                                              ------------    ------------     ------------

        Total production revenues ........    $     57,323    $     90,182     $     76,956
                                              ============    ============     ============
</Table>

2001 COMPARED WITH 2000

     Operating Revenues. During 2001, production revenues decreased 15% to $77.0
million as compared to $90.2 million in 2000. This decrease was principally due
to a 17% decrease in the price received for crude oil, including hedging losses
discussed below, a 1% decrease in the price received for natural gas, including
hedging losses discussed below, and a 22% decrease in natural gas production,
partially offset by a 5% increase in crude oil production.

     During 2001, we experienced a 5% increase in daily crude oil production as
compared to 2000 due to returning wells to production which were previously not
producing due to depressed crude oil prices making it uneconomical to produce or
repair such wells and due to increased drilling activity on our operated
properties. These increases were partially offset by normal production declines,
primarily on our Mississippi crude oil properties and production decreases on
our properties which are operated by third parties.

     The 22% decrease in daily natural gas production during 2001 is due to
production declines on our operated Oklahoma and Mississippi gas properties and
non-operated Oklahoma gas properties. The decline between the comparable periods
is primarily due to several recompletions during late 1999 and early 2000 on our
Oklahoma properties which experienced high initial production but subsequently
experienced rapid production declines and normal production declines on our
Mississippi properties.

     Average crude oil prices (net of hedging losses discussed below) decreased
17% during 2001 compared to the same period in 2000. We experienced a $5.44 per
Bbl decrease in the actual price received from the sale of our




                                       37
<PAGE>

crude oil which was partially offset by a price increase of $1.38 per Bbl due to
a reduction in crude oil hedging losses between the comparable periods.
Substantially all of our Mississippi crude oil is sold under contracts which are
based on posted crude oil prices and substantially all of our Oklahoma crude oil
is sold under a contract which is based on the New York Mercantile Exchange
price. The price per Bbl received is adjusted for the quality and gravity of the
crude oil and is generally lower than the NYMEX price. Our overall average crude
oil price received during 2001 was $20.66 per Bbl, before hedging losses of
$1.41 per Bbl as discussed below, which represented a discount of 20% to the
average NYMEX price for such period.

     Our realized price for our natural gas decreased 1% from $3.73 per Mcf in
2000 to $3.68 per Mcf in 2001, including hedging losses of $.26 per Mcf and $.70
per Mcf, respectively, as discussed below. The fluctuations in the prices for
natural gas are due to market supply and demand and due to current events which
influence market perceptions of supply and demand.

     Production revenues for 2001 included crude oil hedging losses of $5.2
million ($1.41 per BOE) and natural gas hedging losses of $1.1 million ($.70 per
Mcf) as compared to crude oil hedging losses of $9.9 million ($2.79 per BOE) and
natural gas hedging losses of $544,000 ($0.26 per Mcf) for 2000.

     Expenses. Production expenses were $25.1 million for 2001 compared to $23.5
million for 2000. The increase in expenses from 2000 to 2001 is primarily due to
increased electrical costs of approximately $1.9 million due to greater fluid
movement and higher electrical rates which generally fluctuate with changes in
crude oil and natural gas prices.

     Production taxes decreased $931,000 or 16% to $4.8 million during 2001 as
compared to $5.8 million during 2000. This decrease is primarily due to lower
crude oil prices and reinstatement of certain severance tax exemptions due to
lower prices on our Mississippi crude oil production.

     On a BOE basis, production taxes decreased 18% to $1.22 per BOE during 2001
as compared to $1.49 per BOE during 2000 due to lower realized crude oil prices.

     General and administrative costs decreased $1.7 million or 24% between the
comparable periods. This decrease is primarily due to:

     o    reductions of $932,000 in employee-related costs primarily due to
          staff attrition and the termination of corporate office employees and
          officers in April 2000;

     o    reductions of $538,000 in franchise taxes due to refunds for the year
          2000 and reductions of over accrued amounts in 2001;

     o    capitalization of $960,000 of salaries and salary related costs
          associated with exploration and development during 2001 as compared to
          $765,000 during the same period in 2000; and

     o    increases in cost recoveries from working interest owners of $604,000
          during 2001 as compared to 2000 due to an increase in well activity.


                                       38
<PAGE>

These decreases were partially offset by increases of $605,000 in professional
fees.

     Interest expense decreased 2% to $35.5 million in 2001 as compared to $36.2
million in 2000. The following is a summary of interest expense between
comparable periods:

<Table>
<Caption>

                                                  2000             2001
                                              ------------    ------------
                                                     (in thousands)
<S>                                           <C>             <C>
Old bank group loan ......................    $      7,983    $         --
Credit facility ..........................          13,434          14,760
Standby loan .............................          10,090          12,660
Amortization of standby loan original
   issue discount ........................              --           1,636
Amortization of debt issuance costs ......           4,597           6,273
Miscellaneous ............................              88             147
                                              ------------    ------------
                                              $     36,192    $     35,476
                                              ============    ============
</Table>


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

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

     o    higher interest rates and interest rates on our old bank loan during
          the first quarter of 2000 due to payment defaults and debt
          acceleration;

     o    interest on past due interest payments on our old bank group loan
          during the first quarter of 2000; and

     o    lower interest rates on our bank debt during 2001 resulting from
          overall lower market rates.

These decreases were partially offset by:

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

     o    an effective rate of 24.42% on the paid-in-kind interest standby loans
          during 2001;

     o    higher debt issuance amortization expense resulting from $33.9 million
          in debt issuance costs on our new debt;

     o    amortization costs of $1.6 million during 2001 related to the standby
          loan original issue discount which resulted from the adoption of SFAS
          133; and

     o    no accrual of interest on our old unsecured bonds during the first
          quarter 2000 as a result of our bankruptcy filing.

Approximately $3.5 million of additional interest expense would have been
recognized during 2000 if not for the discontinuance of such interest accrual
due to our bankruptcy.

The average interest rate on outstanding indebtedness, excluding interest
expense related to the embedded derivative, was 13.28% in 2001, compared to
12.48% in 2000.


                                       39
<PAGE>

     Gain on standby loan embedded derivative for the year ended December 31,
2001 of $4.1 million represents the change in the fair value of the embedded
derivative during the year excluding the effect of the payment of additional
contingent interest and the issuance of new standby loan notes as follows:


<Table>
<Caption>
                                                                                          Year Ended
                  Standby loan embedded derivative                                     December 31, 2001
                  --------------------------------                                     -----------------

<S>                                                                                   <C>
Fair value at January 1, 2001 .......................................................    $     16,630
Payment of additional contingent interest through issuance of paid in kind notes ....          (4,090)
Issuance of new standby loan notes ..................................................           3,360
Gain on standby loan embedded derivative ............................................          (4,130)
                                                                                         ------------
Fair value at December 31, 2001 .....................................................    $     11,770
                                                                                         ============
</Table>

     Depletion and depreciation expense increased 16% to $17.8 million in 2001
from $15.3 million in 2000. This increase is primarily the result of increased
production volumes and an increased depletion and depreciation rate per BOE,
which was $4.50 in 2001, compared with $3.94 in 2000. 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 the fourth quarter of 2001, we
reclassified unproved property costs totaling $30.6 million that had been
excluded from depletable costs as of December 31, 2000 to costs subject to
depletion at December 31, 2001. These costs were reclassified because most
unproved projects will not be performed in the foreseeable future due to capital
constraints and additionally, certain of the unproved projects are no longer
viewed as economically attractive by our management team. 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 as more fully discussed under "Critical
Accounting Policies and Estimates". 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 2001 or 2000.

     We decided to discontinue our participation in the exploration of two
Tunisia, North Africa permits due to capital commitments during 2001 exceeding
$7 million net to our interest. The two subsidiaries, Coho Anaguid, Inc. and
Coho International Limited, that own these permits filed for protection under
Chapter 11 of the United States Bankruptcy Code on February 20, 2001. During May
2001, Coho International entered into a settlement agreement with the other
joint owners in the permit area. Under this agreement, Coho International
assigned its interest in the Fejaj permit to the other joint owners in exchange
for the assumption by the other joint owners of Coho International's existing
obligations and existing payables under the permit. During July 2001, Coho
Anaguid, Inc. entered into a definitive agreement to sell all of its interest in
the Anaguid permit to Pioneer Natural Resources Company and the other joint
owners in the permit area for cash proceeds of approximately $200,000 and the
assumption of Coho Anaguid's obligations under the permit totaling in excess of
$7 million. These sales agreements have been approved by the United States
Bankruptcy Court and the Tunisian government. We converted the bankruptcy
proceedings for Coho Anaguid and Coho International from Chapter 11
reorganization proceedings to Chapter 7 liquidation proceedings during the first
quarter of 2002 to wind down these proceedings. We have not recorded the
liabilities subject to compromise for these subsidiaries in our consolidated
balance sheet as of December 31, 2001 because these liabilities are solely
obligations of the bankrupt subsidiaries and, furthermore, substantially all of
the obligations of these subsidiaries were assumed under the sales agreements.

     Reorganization costs reflected a gain of $3.2 million in 2001 as compared
to $12.0 million in 2000. During 2000, substantially all estimated
reorganization expenses were accrued, which included:

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

     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;



                                       40
<PAGE>


     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.

During 2001, resolution of claims and settlements of disputed bankruptcy claims
resulted in lower settlement amounts than originally estimated, resulting in a
$2.2 million gain. In addition, our insurer agreed upon a claims settlement for
reimbursement of litigation fees, resulting in a $950,000 gain.

     Accumulated effect of an accounting change for 2001 relates to the adoption
of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities."
SFAS 133 required us to record the fair value at January 1, 2001 of embedded
derivatives contained in certain agreements on the balance sheet with an
offsetting amount in accumulated effect of an accounting change. At January 1,
2001, we recorded the fair value of embedded derivatives for certain leases in
Laurel, Mississippi and the standby loan resulting in a $300,000 loss and $9.5
million gain, respectively. The accumulated effect of the accounting change
related to the standby loan embedded derivative was an increase in net income of
$9.5 million because, under the previous accounting treatment, the changes in
the estimated future additional interest due to changes in forecasted crude oil
and natural gas prices were recorded on an undiscounted basis through earnings
as compared to the fair market value basis under SFAS No. 133 that considers the
time value of the future additional interest payments.

     Loss on extinguishment of debt of $4.4 million for 2000 resulted from the
settlement of the old bank group and bondholders' claims. The loss on settlement
of the old bank group claim was $303,000 and represents the difference in our
carrying value of the debt and the cash settlement amount. The loss on
settlement of the bondholders' claims was $4.1 million and represents the
difference in our carrying value of the debt and the reorganization value of
$10.52 per share for the common stock received by the bondholders.

     Our net operating loss carryforwards for United States and Canadian federal
income tax purposes were approximately $154.7 million at December 31, 2001 and
expire between 2003 and 2021. 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. During 2000, 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 $30.0 million of NOL's which are expected to expire due to the IRC
section 382 limitation.

     Due to the factors discussed above, our net income for 2001 was $4.8
million, as compared to a net loss of $32.7 million for 2000. The loss for 2000
includes a writedown of our Tunisian oil and gas properties of $3.0 million.

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. During 2000, we experienced a 5%
increase in daily crude oil production as compared to 1999 due to returning
wells to production which were previously not producing due to depressed crude
oil prices making it uneconomical to produce or repair such wells and due to
increasing drilling activity on our operated properties.



                                       41
<PAGE>

     The 20% decrease in natural gas production was 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.

     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 which were based on posted crude oil prices. Subsequent to March 1999,
substantially all of our Oklahoma crude oil has been sold under contracts which
are based on 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.

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.



                                       42
<PAGE>

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:

     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.

     Loss on standby loan 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 loss on standby loan embedded
derivative 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,



                                       43
<PAGE>

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.

     During 2000, we 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.

     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;

     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.

     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.

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

     Effect of Price Fluctuations - Hedging Contracts. 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. Currently, all of our
hedge arrangements are with the JPMorgan Chase Bank. At December 31, 2001, we
have hedged a portion of our crude oil production through December 31, 2002. To
calculate the potential effect of the hedging contracts on our operating income,
we applied prices from December 31, 2001 future crude oil price curves for 2002
to the quantity of our oil production hedged for this period. In addition, we
applied December 31, 2001 future crude oil pricing from the price curves
assuming a 10% increase in prices and assuming a 10% decrease in prices. The
estimated increases in operating income through December 31, 2002 resulting from
the hedging contracts are as follows:

<Table>
<Caption>

                       Changes in Operating Income                      2002
                       ---------------------------                   ----------
<S>                                                                  <C>
   Increase based on current price curve                             $2,659,000
   Increase based on 10% decrease in price curve                     $5,262,000
   Increase based on 10% increase in price curve                     $   87,000
</Table>



                                       44
<PAGE>

     Effect of Price Fluctuations - Additional Interest. At December 31, 2001, a
principal amount of $93.5 million was outstanding under our senior subordinated
notes due 2007, which we also refer to as our standby loan agreement. The
standby loan bears interest at a minimum rate of 15% payable semiannually plus
additional interest, after March 31, 2001, 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.
At December 31, 2001, using then current future crude oil and natural gas
curves, we calculated the estimated future additional interest payments due
through December 31, 2002 based on the principal amount of $93.5 million
outstanding at December 31, 2001. In addition, we calculated the estimated
additional interest payments due through December 31, 2002 assuming a 10%
decrease in prices and a 10% increase in prices. The estimated additional
interest due through December 31, 2002 relating to the additional interest under
the standby loan is as follows:

<Table>

<S>                                                           <C>
     Based on current price curve                             $3,027,000
     Based on 10% decrease in price curve                     $2,570,000
     Based on 10% increase in price curve                     $4,205,000
</Table>

Interest payments under the standby loan agreement are required to be
paid-in-kind subject to the intercreditor arrangement between the standby
lenders and the lenders under the senior revolving credit facility unless we
meet specified tests. "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. 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, 2001, included $195 million of floating-rate
debt attributed to bank credit facility borrowing. As a result, our annual
interest cost in 2002 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 50 basis points) would be approximately $975,000 assuming
outstanding debt of $195 million throughout the year. We have locked in a rate
of 5% (2% LIBOR plus 3% margin) thru May 13, 2002 on $175 million of bank credit
facility borrowings.




                                       45
<PAGE>








ITEM 8. FINANCIAL STATEMENTS

<Table>



<S>                                                                                                  <C>
Report of Independent Public Accountants........................................................     47

Consolidated Balance Sheets, December 31, 2000 and 2001.........................................     48

Consolidated Statements of Operations, Years Ended December 31, 1999, 2000 and 2001.............     49

Consolidated Statements of Shareholders' Equity, Years Ended December 31, 1999, 2000 and 2001...     50

Consolidated Statements of Cash Flows, Years Ended December 31, 1999, 2000 and 2001.............     51

Notes to Consolidated Financial Statements, Years Ended December 31, 1999, 2000 and 2001........     52
</Table>





                                       46
<PAGE>




                    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, 2001 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, 2001. 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, 2001 and 2000, and the results of its operations
and its cash flows for each of the three years in the period ended December 31,
2001 in conformity with accounting principles generally accepted in the United
States.

As explained in Note 1 to the financial statements, effective January 1, 2001,
the Company changed its method of accounting for derivative instruments and
hedging transactions.

The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 3 to the
financial statements, the Company has suffered recurring losses and has received
a notice of default from its lenders under its existing bank credit facility and
is in default under the terms of its standby loan agreement that raise
substantial doubt about the Company's ability to continue as a going concern. On
February 6, 2002 the Company, together with certain of its wholly owned
subsidiaries, filed a voluntary petition for relief under Chapter 11 of the U.S.
Bankruptcy Code and is currently operating as a debtor-in-possession subject to
the bankruptcy court's supervision and orders. The financial statements do not
include any adjustments relating to the recoverability and classification of
asset carrying amounts or the amount and classification of liabilities that
might result should the Company be unable to continue as a going concern.

                                              Arthur Andersen LLP

Dallas, Texas
March 29, 2002





                                       47
<PAGE>




                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

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

                                     ASSETS

<Table>
<Caption>

                                                                        DECEMBER 31
                                                                   ----------------------
                                                                     2000         2001
                                                                   ---------    ---------
<S>                                                                <C>          <C>
Current assets
   Cash and cash equivalents ...................................   $   6,661    $   9,779
   Cash in escrow ..............................................       1,042           25
   Accounts receivable, principally trade ......................      11,517        8,198
   Accrued unrealized gains on derivatives .....................          --        2,226
   Other current assets ........................................         483          691
                                                                   ---------    ---------
                                                                      19,703       20,919

Property and equipment, at cost net of accumulated depletion and
   depreciation, based on full cost accounting method (note 4) .     317,667      332,952
Other assets ...................................................      29,421       23,272
                                                                   ---------    ---------
                                                                   $ 366,791    $ 377,143
                                                                   =========    =========
                        LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
   Accounts payable, principally trade .........................   $   5,343    $   4,928
   Accrued liabilities and other payables ......................       9,773        3,815
   Accrued reorganization costs ................................       2,120           75
   Accrued interest ............................................       4,078        1,396
   Accrued unrealized losses on derivatives ....................          --       11,935
   Current portion of long term debt (note 5) ..................       1,036      282,845
                                                                   ---------    ---------
      Total current liabilities ................................      22,350      304,994


Long-term debt, excluding current portion (note 5) .............     282,412        2,710

Long-term derivative liabilities ...............................          --          257

Commitments and contingencies (note 12) ........................         520          450

Shareholders' equity (note 10)
   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 18,714,175 shares .................         187          187
   Additional paid-in capital ..................................     324,070      324,483
   Other comprehensive income ..................................          --        2,004
   Retained deficit ............................................    (262,748)    (257,942)
                                                                   ---------    ---------
      Total shareholders' equity ...............................      61,509       68,732
                                                                   ---------    ---------
                                                                   $ 366,791    $ 377,143
                                                                   =========    =========
</Table>

           SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



                                       48
<PAGE>




                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

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

<Table>
<Caption>
                                                                      YEAR ENDED DECEMBER 31
                                                                  --------------------------------
                                                                    1999        2000        2001
                                                                  --------    --------    --------
<S>                                                               <C>         <C>         <C>
Operating revenues
   Net crude oil and natural gas production ...................   $ 57,323    $ 90,182    $ 76,956
                                                                  --------    --------    --------
Operating expenses
   Crude oil and natural gas production .......................     18,218      23,542      25,147
   Taxes on oil and gas production ............................      2,937       5,778       4,847
   General and administrative (note 4) ........................      9,905       7,137       5,416
   State income tax penalties .................................      1,048          --          --
   Loss on derivatives ........................................         --          --         277
   Allowance for bad debt .....................................         --         765          --
   Depletion and depreciation .................................     13,702      15,316      17,811
   Writedown of crude oil and gas properties ..................      5,433       3,027          --
                                                                  --------    --------    --------
        Total operating expenses ..............................     51,243      55,565      53,498
                                                                  --------    --------    --------
Operating income ..............................................      6,080      34,617      23,458
                                                                  --------    --------    --------
Other income and expenses
   Interest and other income ..................................        246         448         276
   Interest expense (note 5) ..................................    (33,944)    (36,192)    (35,476)
   (Loss) gain on standby loan embedded derivative (note 5) ...         --     (15,163)      4,130
                                                                  --------    --------    --------
                                                                   (33,698)    (50,907)    (31,070)
                                                                  --------    --------    --------
Loss from operations before reorganization costs, income taxes,
   accumulated effect of an accounting change and
   extraordinary item .........................................    (27,618)    (16,290)     (7,612)
                                                                  --------    --------    --------

Reorganization costs (note 2) .................................      3,123      12,004      (3,238)
                                                                  --------    --------    --------

Loss from operations before income taxes, accumulated effect
   of an accounting change and extraordinary item .............    (30,741)    (28,294)     (4,374)
                                                                  --------    --------    --------
Income taxes (note 9)
   Current (benefit) expense ..................................        (26)         --          --
   Deferred (benefit) expense .................................         --          --          --
                                                                  --------    --------    --------
                                                                       (26)         --          --
                                                                  --------    --------    --------
Loss before, accumulated effect of an accounting change and
   extraordinary item .........................................    (30,715)    (28,294)     (4,374)

Accumulated effect of an accounting change ....................         --          --       9,180
Extraordinary item - loss on extinguishment of indebtedness
   (note 2) ...................................................         --      (4,428)         --
                                                                  --------    --------    --------

Net (loss) income .............................................   $(30,715)   $(32,722)   $  4,806
                                                                  ========    ========    ========

Basic and diluted loss per common share (note 1)
   Loss before accumulated effect of an accounting change
     and extraordinary item ...................................   $ (47.99)   $  (1.98)   $   (.23)
   Accumulated effect of an accounting change .................   $     --    $     --    $    .49
   Extraordinary item .........................................   $     --    $  (0.31)   $     --
   Net (loss) income ..........................................   $ (47.99)   $  (2.29)   $    .26
</Table>


           SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




                                       49
<PAGE>




                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

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


<Table>
<Caption>

                                               NUMBER OF                                ACCUMULATED
                                                COMMON                    ADDITIONAL       OTHER       RETAINED
                                                SHARES         COMMON      PAID-IN     COMPREHENSIVE   EARNINGS
                                              OUTSTANDING       STOCK      CAPITAL        INCOME(a)    (DEFICIT)        TOTAL
                                             ------------     --------    ----------   -------------   ---------     -----------
<S>                                          <C>              <C>         <C>          <C>             <C>           <C>
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
     Stock option compensation ...........             --           --          413           --               --           413
     Net income ..........................             --           --           --           --            4,806         4,806
     Change in fair market value of
        hedging derivatives ..............             --           --           --        7,831               --         7,831
     Accumulated effect of an
        accounting change ................             --           --           --       (5,827)              --        (5,827)
                                             ------------     --------    ---------    ---------       ----------    ----------

Balance at December 31, 2001 .............     18,714,175     $    187    $ 324,483    $   2,004       $ (257,942)   $   68,732
                                             ============     ========    =========    =========       ==========    ==========
</Table>


(a) Comprehensive income for the years ended December 31, 1999, 2000 and 2001
was $(30,715), $(32,722) and $6,810, respectively.

           SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





                                       50
<PAGE>




                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)

<Table>
<Caption>

                                                                           YEAR ENDED DECEMBER 31
                                                                    -----------------------------------
                                                                       1999        2000         2001
                                                                    ---------    ---------    ---------
<S>                                                                 <C>          <C>          <C>
Cash flows from operating activities
   Net (loss) income ............................................   $ (30,715)   $ (32,722)   $   4,806
Adjustments to reconcile net (loss) income to net cash provided
     by operating activities:
   Depletion and depreciation ...................................      13,702       15,316       17,811
   Writedown of crude oil and natural gas properties ............       5,433        3,027           --
   Extraordinary item - loss on extinguishment of debt ..........          --        4,428           --
   Standby loan interest ........................................          --       10,090       14,296
   Loss on standby loan embedded derivative .....................          --       15,163       (4,130)
   Accumulated effect of an accounting change ...................          --           --       (9,180)
   Loss on derivatives ..........................................          --           --          (35)
   Amortization of debt issue costs and other ...................         679        6,305        5,448
Changes in:
   Cash in escrow ...............................................       1,427         (964)       1,016
   Accounts receivable ..........................................      (1,194)      (1,622)       3,306
   Other assets .................................................        (454)         945         (382)
   Accounts payable and accrued liabilities .....................      25,981      (10,065)      (8,574)
                                                                    ---------    ---------    ---------

Net cash provided by operating activities .......................      14,859        9,901       24,382
                                                                    ---------    ---------    ---------
Cash flows from investing activities
   Property and equipment .......................................      (6,349)     (25,272)     (33,162)
   Changes in accounts payable and accrued liabilities related to
     exploration and development ................................      (1,186)       2,685       (2,649)
                                                                    ---------    ---------    ---------
Net cash used in investing activities ...........................      (7,535)     (22,587)     (35,811)
                                                                    ---------    ---------    ---------
Cash flows from financing activities
   Increase in long-term debt ...................................       4,600      255,000       15,000
   Debt issuance costs ..........................................          --       (9,732)          --
   Debt extinguishment costs ....................................          --       (2,126)          --
   Repayment of long-term debt ..................................         (20)    (242,600)        (453)
                                                                    ---------    ---------    ---------
Net cash provided by financing activities .......................       4,580          542       14,547
                                                                    ---------    ---------    ---------
Net increase (decrease) in cash and cash equivalents ............      11,904      (12,144)       3,118
Cash and cash equivalents at beginning of year ..................       6,901       18,805        6,661
                                                                    ---------    ---------    ---------
Cash and cash equivalents at end of year ........................   $  18,805    $   6,661    $   9,779
                                                                    =========    =========    =========
Cash paid (received) during the period for:
   Interest .....................................................   $   8,936    $  33,193    $  17,622
   Income taxes .................................................   $      33    $      --    $      --
   Reorganization costs (including prepayments) .................   $   3,352    $   7,501    $   2,471
   Reorganization costs (interest income) .......................   $    (210)   $    (260)   $      --
</Table>


           SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




                                       51
<PAGE>

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001
                  (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 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 were 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
($675,000 and $488,000 at December 31, 2000 and 2001, 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.


                                       52
<PAGE>


                                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, 2001, the Company had unamortized deferred financing charges
associated with the credit facility and standby loan agreement of $2.9 million
and $20.3 million, respectively.

   Asset Retirement Obligations

     In June 2001, SFAS No. 143, "Accounting for Asset Retirement Obligation"
was issued. This statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, a corresponding increase in the carrying amount
of the related long-lived asset would be recorded. Over time, accretion of the
liability is recognized each period, and the capitalized cost is depreciated
over the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss on settlement. The standard is effective for fiscal years beginning after
June 15, 2002, with earlier application encouraged. The Company is currently
evaluating the effect on its financial statements of adopting SFAS No. 143 and
plans to adopt the statement effective January 1, 2003.

   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 and
diluted EPS have been calculated based on the weighted average number of shares
outstanding (including common shares plus, when their




                                       53
<PAGE>
                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)



effect is dilutive, common stock equivalents consisting of stock options and
warrants). Basic and diluted EPS have been calculated on the weighted average
number of shares for the years ended 1999, 2000 and 2001 of 640,088, 14,266,336
and 18,714,175, respectively. In 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.

   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

     The Company adopted SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" effective January 1, 2001. The Statement required 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. The accumulated effect of
this accounting change resulted in an increase in net income of $9.2 million and
a decrease in other comprehensive income ("OCI") of $5.8 million during 2001.
Subsequent changes in fair value for the effective portion of derivatives
qualifying as hedges are recognized in OCI until the sale of the related hedged
production is recognized in earnings, at which time changes in fair value
previously recognized in other comprehensive income are reclassified to earnings
and recognized in operating revenues. Based on the OCI recorded as of December
31, 2001, $2.0 million of deferred net gains on derivatives would be
reclassified to earnings during the next twelve-month period upon the sale of
hedged production. 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 and recognized in loss on derivatives
in the period where the change in fair value occurs. During 2001, the Company
recorded losses on derivatives due to changes in the fair value for the
ineffective portion of derivatives of $494,000. Certain derivatives,
representing 3% of our hedging arrangements at December 31, 2001, which
previously qualified for hedge accounting treatment under SFAS No. 133 failed to
qualify for such treatment during the third quarter of 2001, resulting in a
reduction in loss on derivatives of $266,000 during 2001.

     The Company has entered into certain arrangements that fix a minimum and
maximum price range for a portion of its future crude oil and natural gas
production. The Company entered into these arrangements to reduce the downside
risk associated with potential crude oil and natural gas price declines by
setting a floor price for its future production based on the NYMEX crude oil and
natural gas prices. Due to working capital constraints, the Company entered into
the "costless collar" type of transactions because they do not require upfront
premiums. A significant portion of these hedge arrangements qualify as cash flow
hedges under SFAS No. 133. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital Resources"
for further discussion on the Company's hedge arrangements and a summary of the
Company's existing hedge arrangements.

     The Company has entered into notes in connection with the standby loan
agreement and certain lease agreements which contain provisions for payments
based on crude oil and natural gas prices. These agreements are considered to
include embedded derivatives under SFAS No. 133. See note 5 for additional
discussion on agreements containing embedded derivatives.

   Revenue Recognition Policy

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



                                       54

<PAGE>
                                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 DURING 2000

     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 owned 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. 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 a 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 accepting a dilution in the
         value of their new common stock to obtain the standby loan


                                       55
<PAGE>


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

         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 received 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 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.

3.   BANKRUPTCY PROCEEDINGS - SUBSEQUENT EVENTS

     On November 1, 2001, the lenders under the senior revolving credit facility
notified the Company that its borrowing base under this facility had been
redetermined in the semi-annual review from $195 million to $175 million
effective November 1, 2001 causing a borrowing base deficiency of $20 million as
discussed more fully under Note 5. The Company did not have sufficient working
capital to cure the borrowing base deficiency within the 90 day cure period and
on February 1, 2002 a notice of default was issued by the lenders under the
senior revolving credit facility. The Company is also in default under the terms
of its standby loan agreement. On February 6, 2002, the Company and its wholly
owned subsidiaries, Coho Resources, Inc. and Coho Oil & Gas, Inc., filed a
voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in
the United States Bankruptcy Court for the Northern District of Texas. The
bankruptcy petitions were filed to protect the Company while it develops a
solution to its liquidity problems. The Company is currently operating as
debtor-in-possession under the court's supervision and pursuant to its orders.
The Company filed schedules with the bankruptcy court on March 8, 2002. Those
schedules contain the Company's unaudited, and in some cases, estimated assets
and liabilities as of February 6, 2002, as shown by the Company's accounting
records.



                                       56
<PAGE>
                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)



     Under the cash collateral order, the Company has agreed with the lenders
under the senior credit facility to develop a marketing plan with the Company's
new financial advisor, CIBC, for the sale of its assets or a recapitalization of
its debt and equity. The Company, together with CIBC, is currently working with
the bank group and the unsecured creditors committee on mutually acceptable
terms for this marketing plan to achieve maximum value for the Company's assets
in this process. The marketing plan will allow the Company to explore other
alternatives available, in addition to a sale of the Company's assets, including
a recapitalization of the Company's debt and equity from existing or new
investors to cure the $20 million borrowing base deficiency and to provide
working capital to develop its properties. A recapitalization may include a
partial sale of assets. Any sale or recapitalization will be subject to
bankruptcy court approval under a Chapter 11 plan of reorganization or
liquidation or in accordance with Section 363 of the bankruptcy code, which
generally provides for a partial sale of assets prior to confirmation of a plan
of reorganization or liquidation.

     No adjustments to the carrying value of the Company's assets or liabilities
related to the bankruptcy filing have been reflected in the December 31, 2001
balance sheet. In accordance with SOP 90-07, "Financial Reporting by Entities in
Reorganization under the Bankruptcy Code", during 2002, the Company will adjust
liabilities subject to compromise to its estimate of the allowed claims.
Accordingly, during 2002, the Company will write-off unamortized debt issuance
costs and debt discounts of $22.6 million and $10.7 million, respectively. These
adjustments to the December 31, 2001, carrying values will be recorded in
earnings as reorganization items. In addition, the Company will record the
prepayment penalty ($30.8 million at December 31, 2001) and adjust the recorded
amount of the standby loan embedded derivative, based on the estimated allowed
claims in the first quarter of 2002.

     At this time, it is not possible to predict the outcome of the bankruptcy
proceedings, in general, or the effect on the Company's business or on the
interests of the creditors or shareholders. Management believes, however, that
is may not be possible to satisfy in full all of the claims against the Company.
In addition, the shareholders of the Company may not realize any value on their
investment. As a result of the bankruptcy filing, all of the Company's
liabilities incurred prior to February 6, 2002, including secured debt, are
subject to compromise. Under the bankruptcy code, payment of these liabilities
may not be made except pursuant to a plan of reorganization or liquidation or
bankruptcy court approval.

     The financial statements do not include any adjustments relating to the
recoverability and classification of asset carrying amounts (including $333
million in net property, plant and equipment) or the amount and classification
of liabilities that might result should we be unable to continue as a going
concern. Our ability to continue as a going concern is dependent upon the
confirmation of a plan of reorganization, adequate sources of capital and the
ability to sustain positive results of operations and cash flows sufficient to
continue to explore for and develop proved oil and gas reserves. These factors,
among others, raise substantial doubt concerning our ability to continue as a
going concern.

     Subsequent to February 6, 2001, the Company filed two motions with the
bankruptcy court to seek use of the bank group's cash collateral on an on-going
basis. Since filing bankruptcy, the Company has been operating under two orders
authorizing the use of cash collateral, initially an interim order and currently
a final order which was approved on February 26, 2002 and authorizes
expenditures through April 30, 2002. Under these orders, the Company may pay for
ordinary course of business goods and services incurred after February 6, 2002
that are within the court approved budgets attached to each order. Any
expenditure that is outside the ordinary course of business or that is not
reflected in the approved budgets must be specifically approved by the
bankruptcy court.

4.   PROPERTY AND EQUIPMENT

<Table>
<Caption>
                                                                           December 31
                                                                     ----------------------
                                                                        2000        2001
                                                                     ---------    ---------
<S>                                                                  <C>          <C>
Crude oil and natural gas leases and rights including exploration,
    development and equipment thereon, at cost ...................   $ 709,118    $ 742,214
Accumulated depletion and depreciation ...........................    (391,451)    (409,262)
                                                                     ---------    ---------
                                                                     $ 317,667    $ 332,952
                                                                     =========    =========
</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 $0,
$765,000 and $960,000 in 1999, 2000 and 2001, respectively. During 1999 and the
first quarter of 2000, all overhead expenditures were charged to general and
administrative expense due to the cessation of exploration and



                                       57
<PAGE>
                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

development of crude oil and natural gas reserves during such period. Subsequent
to the first quarter of 2000, the Company increased development work, therefore
related overhead and expenditures were capitalized for the remainder of the year
2000 and 2001.

     During 1999, 2000 and 2001, 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 $30,603,000 and $0
at December 31, 2000 and 2001, respectively, have been excluded from costs
subject to depletion.

     Depletion and depreciation expense per equivalent barrel of production was
$3.63, $3.94 and $4.50 in 1999, 2000 and 2001, respectively. During the fourth
quarter of 2001, the Company reclassified unproved property costs totaling $30.6
million that had been excluded from depletable costs as of December 31, 2000 to
costs subject to depletion at December 31, 2001. These costs were reclassified
because most unproved projects will not be performed in the foreseeable future
due to capital constraints and additionally, certain of the unproved projects
are no longer viewed as economically attractive by the Company's management
team.

5.   LONG-TERM DEBT

<Table>
<Caption>

                                                                      December 31
                                                                 ----------------------
                                                                   2000         2001
                                                                 ---------    ---------
<S>                                                              <C>          <C>
             Credit facility .................................   $ 180,000    $ 195,000
             Standby loan (senior subordinated notes due 2007)      77,358       82,515
             Standby loan interest to be paid-in-kind ........       4,732        3,621
             Standby loan embedded derivative ................      15,163           --
             Promissory notes ................................       5,195        3,419
             Other ...........................................       1,000        1,000
                                                                 ---------    ---------
                                                                   283,448      285,555
             Current maturities of long-term debt ............      (1,036)    (282,845)
                                                                 ---------    ---------

                                                                 $ 282,412    $   2,710
                                                                 =========    =========
</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.

Credit Facility

     The existing senior revolving credit facility was obtained from a syndicate
of lenders led by JP Morgan, as agent for the lenders, and has a maximum loan
commitment amount of $250 million. The credit facility limits permitted advances
to the amount of the borrowing base, which 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 April 1,
2001 redetermination resulted in a decrease in the Company's borrowing base from
$205 million to $195 million. At December 31, 2001, $195 million in advances
were outstanding under the revolving credit facility.

     On November 1, 2001, the lenders under the senior revolving credit facility
notified the Company that its borrowing base under this facility had been
redetermined in the semiannual review from $195 million to $175 million
effective November 1, 2001. On November 2, 2001, the Company received a notice
of borrowing base deficiency because borrowings under this facility exceed the
redetermined borrowing base by $20 million. Under


                                       58
<PAGE>

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

the credit facility, the Company could have remedied the borrowing base
deficiency by providing additional collateral sufficient to eliminate the
borrowing base deficiency or made a cash payment sufficient to eliminate the
borrowing base deficiency on or before January 31, 2002. Currently, all of the
Company's assets are pledged as collateral under the credit facility and the
Company did not have sufficient working capital to make a cash payment that
would eliminate the borrowing base deficiency within the 90 day cure period. On
February 1, 2002, the Company received a notice of default under the credit
facility and subsequently filed a voluntary petition for relief under Chapter 11
of the U.S. Bankruptcy Code. See Note 3 for further discussion on bankruptcy
proceedings.

     At December 31, 2001, the outstanding advances of $195 million under the
senior revolving credit facility were classified as a current liability due to
the default under the credit facility.

     Interest on advances under the credit facility is payable on the earlier of
the expiration of any interest period under the credit facility or quarterly.
Amounts outstanding under the credit facility 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%). In the event any principal is
not paid when due, whether at maturity or upon acceleration, interest will
accrue at the applicable rate, as discussed above, plus 2%. All outstanding
advances are due and payable on March 31, 2003 pursuant to the original terms of
the credit facility.

     The credit agreement contains financial and other covenants including:

     o   maintenance of required ratios of cash flow to interest expense paid or
         payable in cash (not less than 2.75 to 1 for the average of the last
         four consecutive quarters most recently ended December 31, 2001; and
         3.0 to 1 for the average of the last four quarters for any quarter
         ending after January 1, 2002), senior debt to cash flow required (not
         to exceed 3.75 to 1 for the average of the last four quarters most
         recently ended December 31, 2001; and 3.5 to 1 for the average of the
         last four consecutive quarters 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 not less than 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 Company was unable to maintain the required ratio of senior debt to cash
flow and current assets to current liabilities, as required by the credit
agreement during the fourth quarter of 2001. The Company believes that it was in
compliance with all other covenants under the credit facility at the end of the
fourth quarter of 2001. As of December 31, 2001, the covenant ratios of cash
flow to interest expense, senior debt to cash flow, and current assets to
current liabilities were 2.79 to 1, 4.7 to 1, and .06 to 1, respectively.
Non-cash transactions resulting from the adoption and accounting treatment of
SFAS No. 133 are excluded from the calculation of covenant ratios under the
credit facility.

Standby Loan

     The standby loan was made under a senior subordinated note facility under
which the Company issued $72 million of senior subordinated notes, herein
referred to as the "standby loan", to PPM America, Inc., Appaloosa Management,
L.P., Oaktree Capital Management, L.L.C., Pacholder Associates, Inc. and their
respective assignees. At December 31, 2001, an aggregate of $93.5 million of
senior subordinated notes was outstanding under the standby loan. The Company's
rights and responsibilities and those of the standby lenders are governed by a
standby loan agreement dated 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
are payable in an amount equal to 1/2% for every $0.25 that the "actual price"
(as described below) for the Company's oil and gas production exceeds $15 per
barrel of oil equivalent during the applicable



                                       59
<PAGE>

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

semiannual interest period, up to a maximum of 10% additional interest per year.
Any time the average realized price exceeds $20 per barrel of oil equivalent,
the Company will have to pay the 10% maximum additional interest. 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.

     The senior subordinated notes require semiannual interest payments which
are required to be paid-in-kind under the intercreditor arrangement between the
standby lenders and the lenders under the senior revolving credit facility
unless we meet specified financial tests. "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 semiannual interest payments of
$5.8 million were paid-in-kind when due on March 30, 2001 and were reflected at
issuance as an increase in long term debt and long term derivative liabilities
of $4.4 million and $1.4 million, respectively. The standby loan interest
payments of $10.3 million, which were at the maximum interest rate of 25%, were
paid-in-kind when due on September 28, 2001 and were reflected at issuance as an
increase in long term debt and long term derivative liabilities of $8.3 million
and $2.0 million, respectively. Previously, interest accruing on the standby
loan, subsequent to the previous semiannual interest payment was reflected in
long term debt until the next semiannual interest was paid in cash or
paid-in-kind; however, due to the default under the standby loan agreement, as
discussed below, accrued interest at December 31, 2001 was classified as a
current liability.

     The Company adopted SFAS No. 133 effective January 1, 2001. This statement
required the Company to record the fair value of the additional semiannual
interest feature, which is considered an embedded derivative, in long term
derivative liabilities (see Note 6). Accordingly, a debt discount has been
recorded related to the standby loans reflecting the fair value of the embedded
derivatives at the date the original notes were issued. The debt discount is
amortized into interest expense using the straight line method over the term of
the related notes.

     Prior to adoption of SFAS No. 133, which was effective January 1, 2001, the
estimated future additional interest payments were calculated at each balance
sheet date and the change in estimated future additional interest payments was
recorded as long term debt. 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 recorded as long term debt standby loan
embedded derivative during 2000.

     Payment of the standby loan notes will be expressly subordinate to payments
in full in cash of all obligations arising in connection with the 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 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, or may be required to repay, under certain
circumstances, 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. As of
December 31, 2001, the prepayment fee for the then total outstanding principal
amounts, using then current treasury rates, would have been approximately $30.8
million.


                                       60
<PAGE>

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     The standby loan agreement contains certain covenants and cross default
provisions, including cross default provisions which automatically cause the
Company to be in default under the terms of the standby loan agreement in the
event the Company is in default under the senior revolving credit facility or in
the event the Company seeks relief under any provision of the bankruptcy law. In
the event of default, the standby lenders may declare all amounts due under the
standby loan agreement immediately due, unless the default is due to bankruptcy
proceedings, which will automatically accelerate all amounts due, including
principal, accrued interest and the prepayment fee. On February 1, 2002, the
Company received a notice of default under the senior revolving credit facility.
This default automatically caused the Company to be in default under the standby
loan agreement. On February 6, 2002, the Company filed a voluntary petition for
relief under Chapter 11 of the U.S. Bankruptcy Code which automatically
accelerated all amounts due, including the prepayment fee, under the standby
loan. Due to the default under the standby loan agreement, the carrying value of
the Company's outstanding debt at December 31, 2001 was classified as a current
liability. The prepayment fee has not been recorded on the Company's balance
sheet as of December 31, 2001.

     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 has settled claims
with both taxing authorities. Five-year, interest-bearing promissory notes were
issued for settlement of these priority tax claims, of which $2.7 million is
included in long-term debt and $709,000 is included in current portion of long
term debt.

Other

     The Company has settled the claims of Chevron Corp. and Chevron USA for
indemnification of any environmental liabilities in the Brookhaven field. The
terms of this settlement require the Company to fund $2.5 million over a
two-year period to partially finance the implementation of a remediation plan.
The Company paid $1.0 million in June 2000, $500,000 on January 1, 2001 and $1.0
million on January 1, 2002. The $1.0 million payment paid in 2002 is included in
current portion of long term debt.

Debt Repayments

     Based on the balances outstanding under the new credit facility, the
standby loan agreement (excluding unamortized debt discount of $10.9 million),
the promissory notes, and the Chevron settlement, estimated aggregate principal
repayments for each of the next five years are as follows: 2002 - $290,161,000,
2003 - $756,000, 2004 - $805,000, 2005 - $858,000, 2006 - $291,000, and $0
thereafter.

6.   DERIVATIVE LIABILITIES

     The standby loan agreement (see Note 5) 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.
The fair value of the embedded derivative is recorded on the balance sheet and
included in current liabilities as accrued unrealized loss on derivatives in the
amount of $11.8 million at December 31, 2001. The embedded derivative is
classified as a current liability due to the default under the standby loan
agreement as described in Note 5.

     Certain leases in Laurel, Mississippi contain provisions for a portion of
the lease payments to be based on the price of crude oil. These provisions are
considered embedded derivatives under SFAS No. 133 and are recorded at


                                       61
<PAGE>

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


their fair value of $285,000, with $28,000 recorded in current liabilities and
$257,000 in long term derivative liabilities, at December 31, 2001.

7.   COMPREHENSIVE INCOME

     Comprehensive income includes net income and certain items recorded
directly to Stockholders' Equity and classified as OCI. Following the adoption
of SFAS No. 133 on January 1, 2001, the Company recorded a decrease of $5.8
million in OCI and has subsequently recorded additional changes in OCI related
to the Company's crude oil and natural gas hedging arrangements. Comprehensive
income for the years ended December 31, 2000 and December 31, 2001 is as
follows:

<Table>
<Caption>

                                                                      Years Ended
                                                                      December 31,
                                                                 --------------------
                                                                   2000        2001
                                                                 --------    --------
<S>                                                              <C>         <C>
         Net Income (Loss) ...................................   $(32,722)   $  4,806
         Other Comprehensive Income
             Cumulative effect of change in accounting .......         --      (5,827)
             Changes in fair value of open hedging positions .         --       2,548
             Reclassification adjustment for settled contracts         --       5,283
                                                                 --------    --------
         Comprehensive Income (Loss) .........................   $(32,722)   $  6,810
                                                                 ========    ========
</Table>

8.   SUPPLEMENTAL CASH FLOW INFORMATION

     During 1999 and 2001, all noncash transactions were disclosed on the
Consolidated Statements of Cash Flows. 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>


9.   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, 2000 and 2001, were as follows:


                                       62
<PAGE>



                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


<Table>
<Caption>

                                                                                   2000         2001
                                                                                  --------    --------
<S>                                                                               <C>         <C>
     DEFERRED TAX ASSETS
         Net operating loss carryforwards                                         $ 45,487    $ 58,992
         Property and equipment, due to differences in depletion, depreciation,
             amortization and writedowns                                            13,815       2,236
         Alternative minimum tax credit carryforwards                                1,466       1,466
         Employee benefits                                                              25          25
         Reorganization costs                                                        2,103       1,908
         Other                                                                       6,449       3,052
                                                                                  --------    --------
         Total gross deferred tax assets                                            69,345      67,679
         Less valuation allowance                                                  (69,345)    (67,679)
                                                                                  --------    --------
         Net deferred tax assets                                                        --          --
                                                                                  --------    --------
     DEFERRED TAX LIABILITIES
         Property and equipment, due to differences in depletion, depreciation,
             amortization and writedowns                                                --          --
                                                                                  --------    --------
     NET DEFERRED TAX LIABILITY                                                   $     --    $     --
                                                                                  ========    ========
</Table>

     The valuation allowance for deferred tax assets as of December 31, 2000 and
2001 includes $192,665 and $48,095, 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>

                                                                           1999        2000        2001
                                                                         --------    --------    --------
<S>                                                                      <C>         <C>         <C>
     Earnings (loss) before income taxes                                 $(30,741)   $(32,722)   $  4,806
                                                                         ========    ========    ========
     Expected income tax expense (recovery) (statutory rate - 34%)       $(10,452)   $(11,125)   $  1,634
     State taxes - deferred                                                  (913)       (611)       (143)
     Federal benefit of state taxes                                           310         208          49
     Permanent differences                                                    367           9         147
     Expiring operating losses                                              2,390      12,724         140
     Change in valuation allowance                                          8,095      (1,182)     (1,666)
     Other                                                                    177         (23)       (161)
                                                                         --------    --------    --------
                                                                         $    (26)   $     --    $     --
                                                                         ========    ========    ========
</Table>



                                       63
<PAGE>


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


     At December 31, 2001, 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                   2002    $      0
                                                                                        2003           0
                                                                                        2004           0
                                                                                        2005           0
                                                                                   2006-2021     154,539
                                                                                                --------
                                                                                                $154,539
                                                                                                ========

     Operating loss carryforwards for Canadian income tax purposes                 2002-2008    $    127
                                                                                                ========

     Operating loss carryforwards for federal alternative minimum tax
         purposes                                                                  2009-2021    $134,003
                                                                                                ========

     Federal alternative minimum tax credit carryforwards                                 --    $  1,466
                                                                                                ========

     Operating loss carryforwards for Mississippi income tax purposes              2010-2021    $132,512
                                                                                                ========

     Operating loss carryforwards for Oklahoma income tax purposes                 2012-2016    $ 61,459
                                                                                                ========
</Table>


10.  SHAREHOLDERS' EQUITY

     To effect the Company's Plan of Reorganization in 2000, 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;

     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.


                                       64
<PAGE>


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

11. STOCK-BASED COMPENSATION

     Prior to the consummation of the Plan of Reorganization in 2000, 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 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
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,
1999, 2000 and 2001 and changes during the years then ended follows:


<Table>
<Caption>

                                             1999                         2000                         2001
                                    ------------------------    -------------------------     -----------------------
                                                   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       2,631,260    $      6.98     2,238,101    $      7.13     1,031,448   $      8.10
         Granted                           --             --     1,031,448           8.10        15,000          4.55
         Exercised                         --             --            --             --            --            --
         Canceled                     (30,000)          8.42    (2,238,101)          7.13            --            --
         Expired                     (363,159)          5.97            --             --            --            --
                                    ---------    -----------    ----------    -----------     ---------   -----------
     Outstanding at December 31     2,238,101    $      7.13     1,031,448    $      8.10     1,046,448   $      8.05
                                    ---------    -----------    ----------    -----------     ---------   -----------
     Exercisable at December 31
     Available for grant at         2,112,445    $      6.94       295,362    $      7.88       801,080   $      8.01
         December 31

                                      437,668                            0                                          0
</Table>

     Significant option groups outstanding at December 31, 2001 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       736,080         $   8.19           (a)

August 17, 2000             50,000        50,000         $  6.375           (a)

August 1, 2001              15,000        15,000         $   4.55           (a)
</Table>

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


                                       65
<PAGE>


                                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 2000 and 2001 was $4.42 and $2.93 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>
                                1999         2000          2001
                             ----------   ----------    ----------
<S>                          <C>          <C>           <C>

Expected life (years)                --            5             5
Interest rate                        --        6.305%         4.56%
Volatility                           --        42.00%        75.09%
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>
                                                                           1999(b)         2000(b)        2001
                                                                          --------        --------       ------
<S>                                <C>                                   <C>             <C>            <C>

Net (loss) income                   As reported .......................   $(30,715)       $(32,722)      $4,806
                                    Pro forma .........................   $(31,321)       $(34,281)      $3,043
Basic (loss) income per share       As reported .......................   $ (47.99)       $  (2.29)      $  .26
                                    Pro forma . .......................   $ (48.93)       $  (2.40)      $  .16
Diluted (loss) income per share     As reported .......................   $ (47.99)       $  (2.29)      $  .26
                                    Pro forma .........................   $ (48.93)       $  (2.40)      $  .16
</Table>

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

12. 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, 2001, the Company has accrued approximately $500,000 related
     to such costs, of which $50,000 is included in current liabilities and
     $450,000 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 million. A total of $3.3 million
     has been included in depletion and depreciation expense with respect to
     such costs as of December 31, 2001.

(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. The
     Company reached a settlement of the litigation in May, 2001, subject to
     approval of the United States Bankruptcy Court (the "Bankruptcy Court") and
     resolution of certain disputes relating to a matter under seal by order of
     the Bankruptcy Court as discussed below. Final settlement documents were
     signed during October 2001 and approved by the Bankruptcy Court in January
     2002. The disputed termination issue discussed below has not been finalized
     so the final settlement has been extended until April 15, 2002. The Company
     does not expect the settlement to have a material impact on the Company's
     financial position or results of operations.

     Pursuant to the Company's plan of reorganization, shareholders as of
     February 7, 2000, are eligible to receive their pro rata share of 20% of
     the proceeds available from the Hicks Muse lawsuit settlement after fees
     and expenses. The Company has not yet determined the impact, if any, of its
     current bankruptcy proceedings on the distribution of these proceeds to
     shareholders.



                                       66
<PAGE>

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)



(d)  During 2001, the Company became involved in a matter in connection with the
     lawsuit filed by the Company against Hicks Muse. This matter is under seal
     by order of the Bankruptcy Court. The matter involves a termination issue
     and the plaintiff claims damages that are based on a percentage of the
     ultimate amount recovered, if any, in the lawsuit against Hicks Muse. These
     percentages would be calculated on a graduated scale decreasing from 30% to
     10% as the amount recovered increases. Alternatively, the plaintiff claims
     damages on the basis of lost time. However, the Company does not believe
     that either of these methods represents an appropriate measure of damages.
     The Company believes that the claim is without merit. At the order of the
     Bankruptcy Court, certain matters were arbitrated. The arbitration panel's
     sealed findings were forwarded to the Bankruptcy Court and considered in
     conjunction with the final settlement discussed above. The damages awarded
     are currently being appealed by the Company and the plaintiff. The Company
     does not expect this matter to have a material impact on its financial
     position or results of operations. Resolution of this matter may, however,
     impact the amount of proceeds available to the Company from the settlement
     of the Hicks Muse lawsuit.

(e)  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.
     Subsequently, the plaintiff named Ryder Scott Company and Sproule
     Associates Inc., the independent petroleum consultants which evaluate the
     Company's oil and gas reserves, as additional defendants. 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 settlement of the Company's lawsuit against certain
     affiliates of Hicks, Muse, Tate & Furst, as described above, requires
     dismissal of the claims against the former officers. If the suit continues
     against Ryder Scott Company and Sproule Associates Inc., the Company may be
     required to indemnify these companies subject to their terms and conditions
     contained in certain agreements with them, however the Company does not
     expect this matter to have a material impact on the Company's financial
     position or results of operations.

(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 $1,798,000, $1,394,000 and $687,000 in 1999, 2000
     and 2001, respectively. Minimum rentals payable under these leases for each
     of the next five years are as follows: 2002 - $1,162,000; 2003 -
     $1,143,000; 2004 - $1,141,000; 2005 - $1,141,000 and 2006 - $492,000. Total
     rentals payable over the remaining terms of the leases are $3,445,000.

(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 $265,000.



                                       67
<PAGE>


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


13. 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 realized losses of $0, $10,401,000 and
$6,331,000 for 1999, 2000 and 2001, respectively, resulting from these hedging
programs. In addition, realized losses of $313,000 for 2001 are included in loss
on derivatives. At December 31, 2000 and 2001, the Company had no deferred
hedging gains or losses. As of December 31, 2001, the Company had $2.1 million
in net unrealized gains. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resoruces" 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 carrying
value of the credit facility and old bank group loan agreement approximated fair
market value at December 31, 2000 since the applicable interest rate
approximated the market rate. The carrying value of the standby loan notes and
credit facility at December 31, 2001, excluding unamortized debt issuance costs,
was $86.1 million and $195 million, respectively. Due to the default under these
debt agreements in February 2002, the Company does not believe it is practicable
to estimate the fair value of these debt instruments at December 31, 2001.

     During 1999, two purchasers of our crude oil and natural gas, 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. 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. During 2001, EOTT, TEPPCO Crude Oil, L.P. and Sunoco,
Inc. accounted for 41%, 30% and 13%, respectively, of the Company's revenue.
Included in accounts receivable is $114,000, $250,000 and $52,000 from these
customers at December 31, 1999, 2000 and 2001, respectively.

14. 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 received 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) On March 31, 2000, the Company issued $72 million of senior
subordinated notes (see Note 5), 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



                                       68
<PAGE>



                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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:

<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>

     (c) The senior subordinated notes, as discussed in (b) 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
credit agreement, paid-in-kind (see Note 5). On September 29, 2000, March 30,
2001 and September 28, 2001, the semiannual interest payment of $5.4 million,
$5.8 million and $10.3 million, respectively, were 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)
                                                   ------------------------------
                                                      2000               2001
                                                   ----------         ----------
<S>                                                <C>                <C>
PPM America, Inc. and affiliates .............     $    2,923         $    8,761
Appaloosa Management, L.P. and affiliates ....     $    1,170         $    3,507
Oaktree Capital Management, LLC and
  affiliates .................................     $      733         $    2,233
Michael McGovern .............................     $       26         $       78
Gary L. Pittman ..............................     $       13         $       39
Gerald E. Ruley ..............................     $        7         $       22
</Table>

     (d) 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. The agreement called for a monthly retainer of
$15,000 which began on April 1, 2000 and continued through August 2001, at which
time the agreement was terminated. Mr. Davis is Chairman and Chief Executive
Officer of Pirinate Consulting Group, LLC and is currently a director of the
Company.

15. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)

<Table>
<Caption>
                                           First           Second           Third          Fourth           Total
                                        ------------    ------------    ------------    ------------    ------------
<S>                                     <C>             <C>             <C>             <C>             <C>
2001
   Operating revenues ...............   $     20,611    $     20,534    $     19,681    $     16,130    $     76,956
   Operating income (loss) ..........          7,559           5,998           6,024           3,877          23,458
   Net income (loss) ................          6,293          (2,462)         (1,390)          2,365           4,806
   Basic income (loss) per share ....   $        .34    $       (.13)   $       (.07)   $        .13    $        .26
   Diluted income (loss) per share ..   $        .34    $       (.13)   $       (.07)   $        .13    $        .26
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 loss .........................        (14,629)         (2,315)        (23,039)          7,261         (32,722)
   Basic loss per share (restated) ..   $     (17.45)   $       (.12)   $      (1.23)   $        .39    $      (2.29)
   Diluted loss per share (restated)    $     (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)
</Table>


                                       69
<PAGE>


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     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. Quarterly financial data for 1999 and the first quarter of
2000 have been restated to reflect the conversion of old common stock to new
common stock.

16. SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS ACTIVITIES

     Costs Incurred

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

<Table>
<Caption>
                                                                1999           2000           2001
                                                            ------------   ------------   ------------
<S>                                                         <C>            <C>            <C>
Property acquisitions
    Proved ..............................................   $         --   $        432   $         85
    Unproved ............................................             --             --            792
Exploration .............................................          2,198          2,330          1,878
Development .............................................          4,101         22,415         30,268
Other ...................................................             50             95            139
                                                            ------------   ------------   ------------
                                                            $      6,349   $     25,272   $     33,162
                                                            ============   ============   ============
Property and equipment, net of accumulated depletion ....   $    311,788   $    317,667   $    332,952
                                                            ============   ============   ============
</Table>






                                       70
<PAGE>


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

     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, 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
Revisions of previous estimates ..............       (7,827)       (9,337)
Purchase of reserves in place ................           35            --
Sales of reserves in place ...................           --            --
Extensions and discoveries ...................        2,629         2,909
Production ...................................       (3,689)       (1,616)
                                                 ----------    ----------
Estimated reserves at December 31, 2001 ......       87,141        20,667
                                                 ==========    ==========
Proved developed reserves at December 31,
   1999 ......................................       73,748        25,794
   2000 ......................................       65,832        24,453
   2001 ......................................       61,193        15,385
</Table>

     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.


                                       71
<PAGE>


                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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

<Table>
<Caption>
                                                                   1999            2000            2001
                                                               ------------    ------------    ------------
<S>                                                            <C>             <C>             <C>
Future cash inflows ........................................   $  2,562,981       2,597,866       1,483,778
Future production costs ....................................       (642,024)       (760,223)       (575,599)
Future development costs ...................................       (136,589)       (123,636)       (109,777)
Future income taxes ........................................       (435,311)       (419,290)       (103,278)
                                                               ------------    ------------    ------------

Future net cash flows ......................................      1,349,057       1,294,717         695,124
Annual discount at 10% .....................................       (656,182)       (698,428)       (371,052)
                                                               ------------    ------------    ------------
Standardized measure of discounted future net cash flows ...   $    692,875    $    596,289    $    324,072
                                                               ============    ============    ============
Crude oil posted reference price ($ per Bbl)(a) ............   $      25.60    $      26.80    $      19.84
Estimated December 31 Company average realized price
   $/Bbl ...................................................   $      21.78    $      23.72    $      16.41
   $/Mcf(b) ................................................   $       2.25    $      11.18    $       2.57
</Table>

(a)  Based on year end NYMEX prices.

(b)  1999 prices were based on year end posted prices under our gas contracts.
     2000 and 2001 prices were based on the year end NYMEX price of $9.78 per
     MMBTU and $2.57 per MMBTU, respectively.


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

<Table>
<Caption>
                                                                    1999            2000            2001
                                                                ------------    ------------    ------------
<S>                                                             <C>             <C>             <C>

Crude oil and natural gas sales, net of production costs ....   $    (36,168)   $    (60,862)   $    (53,293)
Net changes in anticipated prices and production costs ......        582,297          65,129        (330,337)
Extensions and discoveries, less related costs ..............          7,683          24,387          22,900
Changes in estimated future development costs ...............        (19,335)          1,048             706
Development costs incurred during the period ................          2,212          11,703          13,029
Net change due to sales and purchase of reserves in place ...             --           1,616             169
Accretion of discount .......................................         26,930          79,015          69,006
Revision of previous quantity estimates .....................         45,605         (90,700)        (37,550)
Net changes in income taxes .................................        (97,279)        (63,033)         65,400
Changes in timing of production and other ...................        (88,368)        (64,889)        (22,247)
                                                                ------------    ------------    ------------

Net increase (decrease) .....................................        423,577         (96,586)       (272,217)
Beginning of year ...........................................        269,298         692,875         596,289
                                                                ------------    ------------    ------------
Standardized measure of discounted future net cash flows ....   $    692,875    $    596,289    $    324,072
                                                                ============    ============    ============
</Table>




                                       72
<PAGE>



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

     None








                                       73
<PAGE>


                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE  OFFICERS OF THE REGISTRANT

BOARD OF DIRECTORS

     The names of our directors and other information with respect to each of
them are set forth below. Each of these directors was appointed for a one year
term or until the next annual meeting following the date of appointment. During
August 2001, three directors advised us that they were resigning, effective
immediately, as directors of Coho Energy, Inc. The board vacancies created by
these directors have not been filled and due to our filing for protection under
the bankruptcy code, these positions will remain vacant.

<Table>
<Caption>
         NAME                                       AGE       SINCE
         ----                                       ---      -------
<S>                                                 <C>      <C>

         Michael Y. McGovern(a)..................    50        2000
         Eugene I. Davis(a)(b)...................    47        2000
         Michael E. Salvati(c)(d)................    49        2000
</Table>

(a)  Member of the Compensation Committee.
(b)  Member of the Audit Committee.
(c)  Chairman of the Audit Committee.
(d)  Chairman of the Compensation Committee.

     Michael Y. McGovern. Mr. McGovern has served as our President and Chief
Executive Officer since April 1, 2000. Mr. Govern served as Managing Director of
Pembrook Capital Corporation, an energy investment and advisory services
company, from 1998 until March 31, 2000 and served as Chairman and Chief
Executive Officer for Edisto Resources Corporation, a publicly held oil and gas
company, from 1993 to 1997. Mr. Govern is a director of Greystar Corporation, a
private production management service company; Pioneer Companies, Inc., a public
manufacturing company of chlorine, caustic soda and related products; and
Goodrich Petroleum Corporation, a public oil and gas company.

     Eugene I. Davis. Mr. Davis has served as Chairman and Chief Executive
Officer of Pirinate Consulting Group, L.L.C., a consulting firm specializing in
crisis and turn-around management advisory services for public and private
businesses, since 1999. Mr. Davis served as Chief Operating Officer of Total-Tel
USA Communications, Inc., an integrated telecommunications provider, from 1998
to 1999. He also served in various officer positions, recently as Chief
Executive Officer of RBX Corp., a privately held manufacturer of rubber and
plastic specialty products, since January 2001, and also as its Chairman since
September 2001 and as Vice Chairman and Director, of Emerson Radio Corporation,
an international distributor of consumer electronics products, from 1990 to
1997. Mr. Davis is a director of Eagle Geophysical Corporation, a privately
held seismic company.

     Michael E. Salvati. Mr. Salvati is an independent financial consultant with
Oak Ridge Consulting, Inc. Mr. Salvati also served as Chief Financial Officer of
MarchFirst, a publicly held internet professional services company, during March
and April 2001. During April 2001, MarchFirst filed for protection under Chapter
11 of the U.S. Bankruptcy Code and Mr. Salvati resigned. Mr. Salvati served as
Executive Vice President and Chief Operating Officer of National Financial
Partners Corp., a financial services firm, from 1998 to February 2000. Mr.
Salvati served as Vice President and Chief Financial Officer of Culligan Water
Technologies, Inc., from 1996 to 1998, and was a Partner with KPMG Peat Marwick
LLP, a public accounting firm, prior to 1996. Mr. Salvati is a director of Prime
Succession Inc., a privately held holding company of funeral homes; NCH
Marketing Services, Inc., a privately held marketing services and coupon
processing company; and Lazy Days' RV Center, Inc., a privately held retailer of
recreational vehicles.

     There is no family relationship between any director, executive officer or
person nominated or chosen by the registrant to become a director or executive
officer.



                                       74
<PAGE>


EXECUTIVE OFFICERS

     The names of our executive officers and other information with respect to
them are set forth below:

<Table>
<Caption>
Name                      Age                      Position
----                      ---                      --------
<S>                      <C>      <C>

Michael Y. McGovern        50     President, Chief Executive Officer and Director

Gary L. Pittman            46     Vice President, Chief Financial Officer and
                                    Corporate Secretary

Gerald E. Ruley            61     Vice President-Operations, Exploration, Land
                                    and Reserves

Susan J. McAden            44     Controller and Chief Accounting Officer
</Table>

     For information concerning Michael McGovern, see the table under the
caption "Directors," above.

     Gary L. Pittman has served as our Chief Financial Officer and Corporate
Secretary since April 1, 2000. Mr. Pittman served as Chief Financial Officer of
Bell Geospace, Inc., a privately held technology based provider of high
resolution gradient data to the oil and gas industry, from August 23, 1999 to
March 17, 2000. Bell Geospace was a financial distress start-up company that
engaged Mr. Pittman to assist in developing and executing a strategic business
plan, which included filing bankruptcy on October 4, 1999. In March 2000, Bell
Geospace filed its plan of reorganization and Mr. Pittman resigned. The court
subsequently approved Bell Geospace's plan of reorganization on July 23, 2000.
Mr. Pittman also served as a financial consultant to Perception, Inc., a
privately held manufacturing company, from 1998 to 1999, and as Executive Vice
President and Chief Financial Officer of Convest Energy Corporation, a publicly
traded independent energy company, from 1995 to 1997.

     Gerald E. Ruley has served as our Vice President-Operations since April 1,
2000 and as a Production Manager for Coho since 1996. Mr. Ruley also served as
Exploration and Production Manager of Winchester Production Company, an
independent energy company, from 1994 to 1995.

     Susan J. McAden has served as our Controller and Chief Accounting Officer
since April 1, 2000. Ms. McAden has been employed by us since February 1995 as
Controller and was promoted to Vice President and Controller in January 1998.

     Messrs. McGovern and Pittman were directors and officers of two of Coho's
wholly-owned subsidiaries that filed for protection under Chapter 11 of the
United States Bankruptcy Code in February 2001 as discussed under Part I, Items
1 and 2. "Business and Properties-Oil and Gas Operations-Tunisian Operations."
Mr. Ruley was also a director of these two wholly-owned subsidiaries. Mr. Ruley
and Ms. McAden were officers of one of these two wholly-owned subsidiaries.


ITEM 11. EXECUTIVE COMPENSATION

     The following tables contain information about our most highly compensated
officers, including our Chief Executive Officer, in 1999, 2000 and 2001.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

     To our knowledge, based solely on a review of the copies of reports
required pursuant to Section 16(a) of the Securities Exchange Act of 1934, as
amended, that have been furnished to us and written representations that no
other reports were required during the year ended December 31, 2001, all Section
16(a) filing requirements applicable to our directors, executive officers and
greater than 10% beneficial owners have been met except the Form 4 for Oaktree
Capital Management, LLC related to its common shares sold on May 13, 2001 was
not filed on a timely basis and the Form 4 for Oaktree Capital Management, LLC
related to its common shares sold on August 31, 2001 was not filed on a timely
basis.


                                       75
<PAGE>


                           SUMMARY COMPENSATION TABLE

<Table>
<Caption>
                                                                          LONG-TERM
                                                                        COMPENSATION
                                                                           AWARDS
                                             ANNUAL COMPENSATION         SECURITIES
                                       -----------------------------     UNDERLYING     ALL OTHER
NAME AND PRINCIPAL POSITION             YEAR     SALARY        BONUS     OPTIONS(#)   COMPENSATION
---------------------------            ------    ------        -----    ------------  ------------
<S>                                    <C>     <C>          <C>         <C>           <C>

Michael Y. McGovern                     2001   $  350,000           --           --   $    8,500
  President and Chief Executive         2000      262,494           --      560,825      103,914
     Officer(1)                         1999           --           --           --           --

Gerald E. Ruley                         2001   $  250,000           --           --   $    8,500
  Vice President-Operations,            2000      218,256           --      233,677        8,500
     Exploration, Land and              1999           --           --           --           --
     Reserves(2)

Gary L. Pittman                         2001   $  200,000           --                $    8,500
  Vice President, Chief Financial       2000      150,000           --      186,942       46,805
     Officer and Corporate              1999           --           --           --           --
     Secretary(3)

Susan J. McAden                         2001   $  126,500   $   61,667           --   $   37,732
   Controller and                       2000      111,375       18,333           --       90,599
      Chief Accounting Officer(4)       1999           --           --           --           --
</Table>

(1)  Mr. McGovern has served as our President and Chief Executive Officer since
     April 1, 2000. Mr. McGovern's All Other Compensation includes our
     contributions to a 401(k) savings plan of $8,500 in each of 2001 and 2000
     and $95,414 related to relocation costs in 2000.

(2)  Mr. Ruley has served as our Vice President-Operations, Exploration, Land
     and Reserves since April 1, 2000. Mr. Ruley's All Other Compensation
     includes our contributions to a 401(k) savings plan of $8,500 in each of
     2001 and 2000. Mr. Ruley did not serve as an executive officer during 1999.

(3)  Mr. Pittman has served as our Vice President, Chief Financial Officer and
     Corporate Secretary since April 1, 2000. Mr. Pittman's All Other
     Compensation includes our contributions to a 401(k) savings plan of $8,500
     in 2001 and $7,500 in 2000 and $39,305 related to relocation costs in 2000.

(4)  Ms. McAden has served as our Controller and Chief Accounting Officer since
     April 1, 2000. Ms. McAden's All Other Compensation includes our
     contributions to a 401(k) savings plan of $8,500 in 2001 and $6,485 in
     2000; premiums paid on a disability policy of $1,732 in 2001 and $1,614 in
     2000; and claim settlement payments totaling $27,500 in 2001 and $82,500 in
     2000 associated with the termination of her severance agreement in our
     March 2000 reorganization.

     No options were granted to any officers during 2001.

               AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR

                      AND FISCAL YEAR-END OPTION/SAR VALUES

<Table>
<Caption>
                                                       NUMBER OF SECURITIES              VALUE OF UNEXERCISED
                             SHARES                   UNDERLYING UNEXERCISED             IN-THE-MONEY OPTIONS
                            ACQUIRED                OPTIONS AT FISCAL YEAR-END           AT FISCAL YEAR-END(1)
                               ON        VALUE      ----------------------------     -----------------------------
NAME                        EXERCISE    REALIZED    EXERCISABLE  NON-EXERCISABLE     EXERCISABLE   NON-EXERCISABLE
----                        --------    --------    -----------  ---------------     -----------   ---------------
<S>                         <C>         <C>         <C>          <C>                 <C>           <C>

Michael Y. McGovern            --         $ --        420,619          140,206            $ --           $ --
Gerald E. Ruley                --         $ --        175,257           58,420            $ --           $ --
Gary L. Pittman                --         $ --        140,206           46,736            $ --           $ --
Susan J. McAden                --         $ --             --               --            $ --           $ --
</Table>


                                       76
<PAGE>


(1)  Computed based upon the difference between the market price on December 31,
     2001 of $0.01 per share and the exercise price per share.

EMPLOYMENT AGREEMENTS

     On April 1, 2000, we entered into employment agreements with each of
Messrs. McGovern, Ruley and Pittman, which provide for minimum annual
compensation in the amount of $350,000, $250,000, and $200,000, respectively.
Each employment agreement is for a term of two years, which term automatically
renews daily for a term to extend two years from the renewal date until either
party gives notice. Additionally, each employment agreement automatically
terminates on the date of a "Change of Control," as defined below. Each
employment agreement entitles the officer to participate in the bonus, incentive
compensation and other programs that are created by our board of directors. If
any of Messrs. McGovern, Ruley or Pittman is terminated by Coho without "Cause"
(as defined below), or if the employment agreements are automatically terminated
because of a "Change of Control," Coho would:

     o    pay that individual a cash lump sum payment equal to two times the
          executive's then-current annual rate of total compensation; and

     o    continue, until the second anniversary of the employment termination,
          health and life insurance coverage under our plans or the equivalent
          thereof on the same basis as our other senior executives.

If any of Messrs. McGovern, Ruley or Pittman becomes disabled or dies during the
term of the respective employment agreement, the employment agreement may be
terminated by us, and we will pay the executive or his estate any unpaid
compensation and other benefits under the employment agreement until the date of
termination.

     The term "Cause" is defined in each employment agreement generally to mean:

     o    any material failure of the executive after written notice to perform
          his or her duties;

     o    commission of fraud, embezzlement or misappropriation by the executive
          against Coho;

     o    a material breach by the executive of the employment agreement or of
          the fiduciary duty owed to Coho; or

     o    conviction of the executive of a felony offense or a crime involving
          moral turpitude.

     Under each employment agreement, a "Change of Control" of Coho is deemed to
     have occurred if:

     o    there is a sale, lease or other transfer of all or substantially all
          of the assets of Coho;

     o    our shareholders adopt a plan relating to the liquidation or
          dissolution of Coho;

     o    any person or group of persons acting in concert becomes the
          beneficial owner of more than 50 percent of the voting power of our
          securities generally entitled to vote in the election of directors,
          with certain exceptions; or

     o    there occurs a merger or consolidation of Coho unless, after the
          transaction, all of those persons who were the beneficial owners of
          our common stock before the transaction beneficially own 50 percent or
          more of the total voting power of all securities generally entitled to
          vote in the election of directors, managers or trustees of the
          surviving entity.

     On April 3, 2000, we entered into an executive employment severance
agreement with Jeffrey Clarke, our former president and chief executive officer.
The purpose of this agreement was to compromise and settle any claims Mr. Clarke
may have had under his prior employment agreement and to secure Mr. Clarke's
assistance in the lawsuit we filed against Hicks Muse. In addition, Mr. Clarke
agreed to serve as a consultant to us for up to two days per week through June
30, 2000. Under the compromise and settlement agreement, Mr. Clarke received a
total of $875,000 as a cash settlement, $412,500 of which was paid in April 2000
and $462,500 of which was paid in



                                       77
<PAGE>


January 2001. We also agreed to pay two years of medical insurance, life
insurance and disability insurance aggregating approximately $86,000 for the two
year period.

     In addition, under the agreement, Mr. Clarke is entitled to the following
non-cash benefits:

     o    release of any claims we may have in connection with the non-interest
          bearing sole recourse loan made to Mr. Clarke in October 1997 to
          assist him in the exercise of expiring options;

     o    forebearance of the interest-free loan from us to Mr. Clarke in the
          amount of $205,000 used to purchase a house, in exchange for Mr.
          Clarke's assistance in the Hicks Muse lawsuit, which loan will be
          forgiven on the date the Hicks Muse lawsuit is settled or otherwise
          concluded;

     o    a three-year directors' and officers' insurance policy covering
          actions prior to the effective date of our March 2000 plan of
          reorganization; and

     o    our agreement not to assign any claims we may have against Mr. Clarke,
          if any.

     Also on April 13, 2000, we entered into an agreement with Susan J. McAden,
our Controller and Chief Accounting Officer, related to her former position as
our Vice President and Controller, to compromise and settle her claim under her
previous severance agreement, which was rejected under our March 2000 plan of
reorganization. Under the compromise and settlement agreement, Ms. McAden
received a $110,000 cash settlement, $82,500 of which was paid in 2000 and
$27,500 of which was paid in January 2001.

     We have entered into an executive stay agreement with Ms. McAden which is
designed to encourage her to continue to carry out her duties with us in the
event we have a change in control. If she, subsequent to a change of control,
continues to be employed by us for a period of greater than 180 days or if her
employment is terminated for other than cause, this stay agreement generally
provides for a payment in an amount equal to her annual salary.

     In March 2002, we filed two separate motions with the bankruptcy court
requesting authorization to implement a senior management incentive retention
program and a key employee retention program. These programs have not been
approved by the bankruptcy court as of March 31, 2002. The following discussion
describes the material terms of the retention programs as proposed.

     The senior management incentive retention program includes Messrs.
McGovern, Pittman and Ruley. Consistent with the terms of their employment
contracts, each will be entitled to receive stay retention payments totaling two
times their annual base salaries until the earlier of:

     o    the confirmation of a plan of reorganization;

     o    the sale of substantially all of our assets;

     o    our conversion to Chapter 7; or

     o    their termination other than for cause.

Any entitlement to payments for such officer will be forfeited if he resigns
prior to the occurrence of one of these events.

     The key employee retention program includes Ms. McAden. Consistent with the
terms of her executive stay agreement, she will be entitled to receive a stay
retention payment equal to one year of her annual base salary upon the
occurrence of the events previously listed under the senior management program
and she is subject to the same forfeiture provision.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

     At December 31, 2001, the members of our compensation committee were
Michael E. Salvati, Eugene I. Davis and Michael Y. McGovern. Mr. McGovern has
also served as our president and chief executive officer since


                                       78
<PAGE>


April 1, 2000. No other member of our compensation committee was an officer or
employee of Coho at any time during 2001.

     During 2001, no executive officer of Coho served as:

     o    a member of the compensation committee or other board committee
          performing equivalent functions (or, in the absence of any such
          committee, the board of directors) of another entity, one of whose
          executive officers served on the compensation committee of our board
          of directors;

     o    director of another entity, one of whose executive officers served on
          the compensation committee of our board of directors; or

     o    a member of the compensation committee or other board committee
          performing equivalent functions (or, in the absence of any such
          committee, the board of directors) of another entity, one of whose
          executive officers served as a director of Coho.

COMPENSATION OF DIRECTORS

     Directors who are not our employees receive an annual retainer of $15,000
plus a fee of $1,000 for each meeting of our board of directors or meeting of a
committee of our board of directors attended in person and $500 for each
telephonic board meeting. Additionally, members of the Audit, Compensation and
Executive Committees will receive an annual fee of $2,000, with the exception of
the chairman of each Committee, who will receive an annual chairman fee of
$3,500. All directors are reimbursed for expenses incurred in attending meetings
of our board of directors or meetings of committees of our board of directors.
Our employees who are also directors do not receive a retainer or fees for
attending meetings of our board of directors or meetings of committees of our
board of directors.

     On April 1, 2000, we entered into an agreement with Pirinate Consulting
Group, LLC with respect to monthly financial advisory services to be performed
by Eugene I. Davis for us for a monthly retainer of $15,000. This agreement was
terminated effective August 31, 2001. Mr. Davis is Chairman and Chief Executive
Officer of Pirinate Consulting Group, LLC and is currently one of our directors.

NON-EMPLOYEE DIRECTOR STOCK OPTION PLAN

     On August 17, 2000, we adopted a non-employee director stock option plan
for our current non-employee directors. On August 17, 2000, each non-employee
director received options to purchase 10,000 shares of our common stock at a
price per share equal to the closing sale price of our common stock on August
17, 2000. In addition, on August 1 of each year thereafter the directors are
each entitled to receive options to purchase an additional 5,000 shares of our
common stock at the closing sale price on the date of grant.

     Options granted under the non-employee director stock option plan are fully
exercisable on the date of grant and must be exercised within five years from
the date of grant. The options terminate on the earlier of the date of the
expiration of the option or one year after the date the optionee ceases to serve
as a director of Coho.

REPORT OF THE COMPENSATION COMMITTEE WITH RESPECT TO COMPENSATION OF EXECUTIVE
OFFICERS

To the Board of Directors
Coho Energy, Inc.

OBJECTIVES

     The objective of the Compensation Committee is to develop compensation
policies which will provide incentives to key executives to develop and carry
out Coho's business strategy that will result in the maximization of return to
the shareholders. More specifically, the Compensation Committee's objectives are
to develop compensation policies which will:

     o    allow Coho to attract and retain qualified individuals;



                                       79
<PAGE>


     o    encourage achievement of Coho's short term and long term goals; and

     o    align executive remuneration with the interest of shareholders by
          linking a significant portion of executive compensation to the
          appreciation of the share price of the common stock.

     The Compensation Committee's philosophy toward executive compensation is to
provide a combination of base level cash compensation and annual incentives, as
well as providing longer term awards through a stock option plan. No stock
options were granted to Messrs. McGovern, Pittman and Ruley during 2001.
Executives are also permitted to participate in a health benefits insurance
program and a 401 (k) plan, each of which is available to all employees of Coho.

Base Compensation

     The minimum cash compensation levels set forth in the 2000 employment
agreements for Messrs. McGovern, Ruley and Pittman were based on such factors as
the executives' levels of responsibility, prior experience, breadth of knowledge
and compensation paid to similarly situated executives employed by oil and gas
companies with capitalizations similar to Coho and with experience in directing
a company emerging from a bankruptcy reorganization. The Compensation
Committee's review and analysis of these matters was subjective in nature, with
no particular weight being placed on any specific factors. No adjustments were
made to these compensation levels during 2001.

Annual Incentives

     Although the employment agreements for Messrs. McGovern, Ruley and Pittman
entitle them to participate in bonus and incentive compensation programs, no
such programs have been implemented.

                                      Respectfully submitted,


                                      COMPENSATION COMMITTEE
                                      Michael E. Salvati
                                      Eugene I. Davis
                                      Michael Y. McGovern









                                       80
<PAGE>


PERFORMANCE GRAPH

     The following graph compares, as of December 31 for each of the dates
indicated, the percentage change in cumulative total stockholder return on our
common stock with the cumulative total return of the Standard & Poor's 500 Index
and the Standard Industrial Code Index for Crude Oil and Natural Gas Producers.
The graph assumes that the value of the investment in our common stock and each
index was $100 at December 31, 1996 and that all dividends paid by those
companies included in the indices were reinvested.


                               [PERFORMANCE GRAPH]

                 COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
                   AMONG COHO ENERGY, INC., THE S&P 500 INDEX
                                AND A PEER GROUP

<Table>
<Caption>
                                              Cumulative Total Return
                           ---------------------------------------------------------------
                            12/96       12/97      12/98      12/99      12/00      12/01
                           --------   --------   --------   --------   --------   --------
<S>                        <C>        <C>         <C>         <C>       <C>         <C>

COHO ENERGY, INC             100.00     128.07      39.44       6.14      45.61       0.52
S & P 500                    100.00     133.36     171.47     207.56     188.66     166.24
PEER GROUP                   100.00      92.19      45.49      49.05     107.64      79.88
</Table>

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The following table sets forth information as to persons or entities who,
to our knowledge based on information received from those persons or entities,
were the beneficial owners of more than 5% of the outstanding shares of common
stock as of March 15, 2002. Unless otherwise specified, these persons have sole
voting power and sole dispositive power with respect to all shares attributable
to them.

<Table>
<Caption>
                                                              Common Stock
                                            -----------------------------------------------
                                            Amount and Nature of
Name and Address of Beneficial Owner        Beneficial Ownership        Percent of Class(1)
------------------------------------        --------------------        -------------------
<S>                                        <C>                         <C>

PPM America, Inc.(2)                               6,721,076                   35.9%
225 West Wacker Drive, Suite 1200
Chicago, Illinois  60606

Oaktree Capital Management, LLC(3)                 4,366,885                   23.3%
333 South Grand Avenue, 28th Floor
Los Angeles, California 90071

Appaloosa Management, L.P.(4)                      3,404,936                   18.2%
26 Main Street
Chatham, New Jersey  07928
</Table>


                                       81
<PAGE>


(1)  Based on 18,714,175 shares issued and outstanding as of March 15, 2002.

(2)  Based on information contained in a Schedule 13D filed April 26, 2001 filed
     with the Commission. PPM America, Inc. has shared voting and dispositive
     power with respect to 6,721,076 shares of new common stock that are owned
     by it.

(3)  Based on information contained in Form 5 filed February 13, 2002 with the
     Commission. Oaktree Capital Management, LLC has sole voting and dispositive
     power with respect to 4,366,885 shares of Common Stock that are owned by
     it.

(4)  Based on information contained in a Schedule 13D filed December 18, 2001
     filed with the Commission. Appaloosa Management, L.P. is a limited
     partnership and has sole voting and dispositive power with respect to
     3,384,936 shares of new common stock that are owned by the partnership. The
     number of shares shown as beneficially owned includes the 20,000 shares
     that may be acquired upon the exercise of stock options held by two former
     directors for the benefit of Appaloosa Management, L.P.


     The following table sets forth information with respect to common stock
beneficially owned as of March 15, 2002 by each of our directors, by each
executive officer named in the Summary Compensation Table and by all directors
and officers as a group. Unless otherwise specified, these persons have sole
voting power and sole dispositive power with respect to all shares attributable
to him or her.

<Table>
<Caption>
                                                                     AMOUNT AND NATURE OF
                                                                     BENEFICIAL OWNERSHIP       PERCENT OF CLASS(1)
                                                                     --------------------       -------------------
<S>                                                                  <C>                        <C>

Eugene I. Davis(2) ...............................................            15,000                       *
Susan J. McAden ..................................................                --                      --
Michael Y. McGovern(3) ...........................................           573,925                     3.1%
Gerald E. Ruley(3) ...............................................           238,295                     1.3%
Gary L. Pittman(3) ...............................................           193,492                     1.0%
Michael E. Salvati(2) ............................................            15,000                       *
All directors and executive officers as a group (6 persons) ......         1,035,712                     5.5%
</Table>

* Less than 1%

(1)  Based on 18,714,175 shares issued and outstanding as of March 15, 2002.

(2)  Includes 15,000 shares that may be acquired upon exercise of stock options
     held by each of Mr. Davis and Mr. Salvati.

(3)  The numbers of shares shown as beneficially owned by Messrs. McGovern,
     Pittman and Ruley include 560,825, 233,677, and 186,942 shares,
     respectively, that may be acquired upon exercise of stock options within 60
     days. Included in Mr. Ruley's total shares are 1,496 shares which are held
     by a family trust; Mr. Ruley disclaims any beneficial ownership interest in
     these shares.


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     On March 31, 2000, and in connection with the consummation of our March
2000 plan of reorganization, we issued $72 million of senior subordinated notes,
of which $65.5 million were issued to three of our 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 an aggregate of 2,694,841 shares of our common stock. Share information,
loan origination fees and notes purchased by our major shareholders are as
follows:



                                       82
<PAGE>


<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 of our officers were entitled, under
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 our officers are as
follows:

<Table>
<Caption>
                                                                              Loan Origination         Senior Notes
                                                         Common Shares         Fee (in 000's)      Purchased (in 000's)
                                                         -------------        ----------------     --------------------
<S>                                                      <C>                  <C>                  <C>

Michael Y. McGovern .................................        13,100                 $12.5                  $350
Gary L. Pittman......................................         6,550                 $ 6.0                  $175
Gerald E. Ruley......................................         3,743                 $ 3.5                  $100
</Table>

     The senior subordinated notes, as discussed above, require semiannual
interest payments payable in cash or, if required pursuant to the intercreditor
arrangement between the standby lenders and the lenders under our bank credit
agreement, paid-in-kind.

     On September 29, 2000, March, 30, 2001 and September 28, 2001, the
semiannual interest payment of $5.4 million, $5.8 million and $10.3 million,
respectively, were 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)
                                                     ------------------------------
                                                          2000           2001
                                                      ------------   ------------
<S>                                                   <C>            <C>

PPM America, Inc. and affiliates .................    $      2,923   $      8,761
Appaloosa Management, L.P. and affiliates ........    $      1,170   $      3,507
Oaktree Capital Management, LLC and affiliates ...    $        733   $      2,233
Michael Y. McGovern ..............................    $         26   $         78
Gary L. Pittman ..................................    $         13   $         39
Gerald E. Ruley ..................................    $          7   $         22
</Table>

     On April 1, 2000, we entered into an agreement with Pirinate Consulting
Group, LLC with respect to monthly financial advisory services to be performed
by Eugene I. Davis for us for a monthly retainer of $15,000. This agreement was
terminated effective August 31, 2001. Mr. Davis is Chairman and Chief Executive
Officer of Pirinate Consulting Group, LLC and is currently one of our directors.

     We have 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 us in the event we have a change in control. If the employee,
subsequent to a change in control, continues to be employed by us for a period
of greater 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 the employee's annual salary. The change of control payments paid to
the key employees covered under such severance agreements would aggregate
approximately $406,000.

     Pursuant to a registration rights agreement dated March 31, 2000, we have
agreed to register all shares of our common stock owned, currently or in the
future, by PPM, Appaloosa, Oaktree and Pacholder Associates, Inc. In accordance
with the registration rights agreement, we have filed a shelf registration
statement which became effective on January 8, 2001 and have agreed to keep the
shelf registration statement effective until the earlier of


                                       83
<PAGE>


three years from the date of effectiveness or the time when the shares of common
stock covered by the registration rights agreement have been sold or may be sold
without restriction. We have a limited right to suspend the availability of the
shelf registration statement for a valid business purpose for up to two
consecutive 30-day periods or to prevent the disclosure of material non-public
information. Due to our default under the senior credit facility, the shelf
registration statement is currently not available.

     Further, holders of at least 10% of all common stock covered by the
registration rights agreement may request that we register shares for sale in
the manner specified in the request. Each of PPM, Appaloosa, Oaktree and
Pacholder is entitled to three demand registrations. However, they may request a
registration on Form S-3 and if Form S-3 is available to us, there is no limit
on the number of registrations on Form S-3 that we are obligated to effect. We
have a limited right to delay the filing of a registration statement pursuant to
these demands to prevent the disclosure of material non-public information. In
addition, any time we file a registration statement, holders of common stock
covered by the registration rights agreement will have the right to request the
inclusion of their shares in the registration. The number of shares requested to
be registered (except those under the shelf registration statement) may be cut
back, on a pro rata basis, by the managing underwriter in a public offering to
ensure the successful marketing of a smaller number of shares.






                                       84
<PAGE>


                                     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

EXHIBIT
NUMBER                             DESCRIPTION
-------                            -----------

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

 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 (incorporated by
              reference to the Company's Annual Report on Form 10-K for the year
              ended December 31, 2000).

 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)).


                                       85
<PAGE>


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 Charles E.
              Gibson and Susan J. McAden (incorporated by reference to the
              Company's Annual Report on Form 10-K for the year ended
              December 31, 2000).

10.10     -   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).

10.11     -   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).

10.12     -   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)).

10.13     -   Crude Oil Purchase Agreement dated October 1, 2000, by and between
              Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M) (incorporated by
              reference to the Company's Annual Report on Form 10-K for the year
              ended December 31, 2000).

10.14     -   Crude Oil Purchase Agreement dated September 20, 2000, by and
              between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P.
              (incorporated by reference to the Company's Annual Report on Form
              10-K for the year ended December 31, 2000).

10.15     -   Crude Oil Purchase Contract dated December 19, 2000, by and
              between Coho Resources, Inc. and EOTT Energy Operating Limited
              Partnership (incorporated by reference to the Company's Annual
              Report on Form 10-K for the year ended December 31, 2000).

10.16     -   Letter agreement dated November 30, 2001, by and between Coho
              Resources, Inc. and EOTT Energy Operating Limited Partnership,
              amending the crude oil purchase contract dated December 19, 2000,
              by and between Coho Resources, Inc. and EOTT Energy Operating
              Limited Partnership.

10.17     -   Letter Agreement dated September 9, 2001 by and between Coho Oil &
              Gas, Inc. and Sunoco, Inc. (R&M), amending the crude oil purchase
              agreement dated October 1, 2000, by and between Coho Oil & Gas,
              Inc. and Sunoco, Inc. (R&M).


                                       86
<PAGE>


 10.18    -   Fifth Amendment to Crude Oil Purchase Agreement dated November 5,
              2001, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil,
              L.P., amending the crude oil purchase agreement dated September
              20, 2000, by and between Coho Oil & Gas, Inc. and TEPPCO Crude
              Oil, L.P.

 10.19    -   Second Amendment to Credit Agreement dated April 20, 2001 among
              Coho Energy, Inc., The Chase Manhattan Bank, Fortis 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.

 10.20    -   Letter Agreement dated November 16, 2001, by and between Coho
              Energy, Inc. and CIBC World Markets Corp.

 10.21    -   Non-employee Director Option Plan.

 21.1     -   List of Subsidiaries of the Company (filed herewith).

 99.1     -   Letter dated April 5, 2002 to the United States Securities
              and Exchange Commission regarding December 31, 2001 year-end
              audit performed by Arthur Andersen.


* 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 2002 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.





                                       87
<PAGE>




                                   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: April 5, 2002                 By: /s/ MICHAEL MCGOVERN
                                        -------------------------------------
                                        Michael Y. 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 Y. MCGOVERN             President, Chief Executive         April 5, 2002
--------------------------             Officer and Director
Michael McGovern

/s/ GARY L. PITTMAN                 Vice President and Chief           April 5, 2002
--------------------------             Financial Officer
Gary L. Pittman

/s/ SUSAN J. MCADEN                 Controller and Chief               April 5, 2002
--------------------------             Accounting Officer
Susan J. McAden

/s/ EUGENE I. DAVIS                 Director                           April 5, 2002
--------------------------
Eugene I. Davis

/s/ MICHAEL E. SALVATI              Director                           April 5, 2002
--------------------------
Michael E. Salvati
</Table>



                                       88
<PAGE>

                               INDEX TO EXHIBITS

<Table>
<Caption>
EXHIBIT
NUMBER                             DESCRIPTION
-------                            -----------
<S>           <C>

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

 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 (incorporated by
              reference to the Company's Annual Report on Form 10-K for the year
              ended December 31, 2000).

 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)).
</Table>


<PAGE>


<Table>
<S>           <C>
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 Charles E.
              Gibson and Susan J. McAden (incorporated by reference to the
              Company's Annual Report on Form 10-K for the year ended
              December 31, 2000).

10.10     -   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).

10.11     -   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).

10.12     -   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)).

10.13     -   Crude Oil Purchase Agreement dated October 1, 2000, by and between
              Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M) (incorporated by
              reference to the Company's Annual Report on Form 10-K for the year
              ended December 31, 2000).

10.14     -   Crude Oil Purchase Agreement dated September 20, 2000, by and
              between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P.
              (incorporated by reference to the Company's Annual Report on Form
              10-K for the year ended December 31, 2000).

10.15     -   Crude Oil Purchase Contract dated December 19, 2000, by and
              between Coho Resources, Inc. and EOTT Energy Operating Limited
              Partnership (incorporated by reference to the Company's Annual
              Report on Form 10-K for the year ended December 31, 2000).

10.16     -   Letter agreement dated November 30, 2001, by and between Coho
              Resources, Inc. and EOTT Energy Operating Limited Partnership,
              amending the crude oil purchase contract dated December 19, 2000,
              by and between Coho Resources, Inc. and EOTT Energy Operating
              Limited Partnership.

10.17     -   Letter Agreement dated September 9, 2001 by and between Coho Oil &
              Gas, Inc. and Sunoco, Inc. (R&M), amending the crude oil purchase
              agreement dated October 1, 2000, by and between Coho Oil & Gas,
              Inc. and Sunoco, Inc. (R&M).
</Table>


<PAGE>



<Table>
<S>           <C>
 10.18    -   Fifth Amendment to Crude Oil Purchase Agreement dated November 5,
              2001, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil,
              L.P., amending the crude oil purchase agreement dated September
              20, 2000, by and between Coho Oil & Gas, Inc. and TEPPCO Crude
              Oil, L.P.

 10.19    -   Second Amendment to Credit Agreement dated April 20, 2001 among
              Coho Energy, Inc., The Chase Manhattan Bank, Fortis 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.

 10.20    -   Letter Agreement dated November 16, 2001, by and between Coho
              Energy, Inc. and CIBC World Markets Corp.

 10.21    -   Non-employee Director Option Plan.

 21.1     -   List of Subsidiaries of the Company (filed herewith).

 99.1     -   Letter dated April 5, 2002 to the United States Securities
              and Exchange Commission regarding December 31, 2001 year-end
              audit performed by Arthur Andersen.
</Table>


* Represents management contract or compensatory plan or arrangement.