<PAGE>   1


                       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, 1996
                                       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)

<TABLE>
<S>                                                                          <C>
          Texas                                                                    75-2488635       
-------------------------------                                            -----------------------
(State or other jurisdiction of                                                 (IRS Employer
incorporation or organization)                                               Identification Number)

14785 Preston Road, Suite 860
Dallas, TX                                                                      75240  
---------------------------------------                                       ---------
(Address of principal executive offices)                                        (Zip Code)
</TABLE>

              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 if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.         [ X ]

         As of February 28, 1997, 20,375,126 shares of the registrant's Common
Stock were outstanding and the aggregate market value of all voting stock held
by non-affiliates was $102.5 million based upon the closing price on the NASDAQ
National Market System on such date.  (The officers and directors of the
registrant are considered affiliates for purposes of this calculation).

                      DOCUMENTS INCORPORATED BY REFERENCE

         There is incorporated by reference in Part III of this Annual Report
on Form 10-K certain information contained under the headings  "Directors and
Executive Officers of the Registrant", "Executive Compensation", "Certain
Relationships and Related Transactions" and "Security Ownership of Certain
Beneficial Owners and Management" in the registrant's Proxy Statement for the
Company's Annual Meeting of Shareholders proposed to be held May 12, 1997,
which Proxy Statement shall be filed within 120 days of the end of the
Registrant's fiscal year.
<PAGE>   2
PART I

ITEM 1.  BUSINESS AND PROPERTIES

GENERAL

         Coho Energy, Inc. is an independent oil and gas company engaged in the
development and production of, and exploration for, oil and gas.  The Company's
oil activities are concentrated principally in Mississippi where it is that
state's largest producer of crude oil.  The Company's natural gas activities
are concentrated principally in Louisiana.  At December 31, 1996, the Company's
total proved reserves were 53.7 MMBOE with a Present Value of Proved Reserves
of $417.1 million, approximately 76% of which were proved developed reserves.
At December 31, 1996, crude oil comprised 65%  of Coho's total proved reserves
and the Company's reserve-to-production ratio was 15.0 years.

         The Company's average net daily production has increased from 1,610
BOE in 1988 to 9,769 BOE  in 1996.  Over the five-year period ended December
31, 1996, the Company discovered or acquired approximately  42.3 MMBOE of
proved reserves at an average finding cost of $4.89 per BOE.

         The Company's business strategy is as follows:

         o       Acquire underdeveloped oil and gas properties, primarily in
                 the interior salt basin of Mississippi, which have geological
                 complexity and multiple producing horizons.  Management
                 believes that the Company's extensive experience in the
                 interior salt basin of Mississippi developed over the past ten
                 years enables it to efficiently increase reserves and improve
                 production rates in this complex geologic environment.
                 Additionally, management believes that such experience gives
                 the Company a significant competitive advantage in evaluating
                 similarly situated acquisition prospects;

         o       Maximize production and continue to increase reserves through
                 relatively low risk activities such as development/delineation
                 drilling; including high-angle and horizontal drilling,
                 multi-zone completions, recompletions, enhancement of
                 production facilities and secondary recovery projects;

         o       Utilize 3-D seismic technology to identify exploration
                 prospects and develop reserves in the vicinity of its existing
                 fields.  The Company began using 3-D seismic technology in the
                 Laurel field in Mississippi in 1983 and has shot two large 3-D
                 seismic programs in and around its existing properties in 1995
                 and 1996;

         o       Achieve a low cost structure through asset concentration in
                 the interior salt basin of Mississippi.  Asset concentration
                 permits operating economies of scale and leverages operational
                 and technical capabilities.  Moreover, Coho continuously
                 reviews its producing properties for operating efficiencies.
                 A typical Coho operated Mississippi salt basin well is highly
                 productive, further reducing operating costs on a per well and
                 per BOE basis;

         o       Control the magnitude, quality and timing of capital
                 expenditures by obtaining high working interests in and
                 operating its properties.  At December 31, 1996 the Company
                 owned an average working interest of 87% and operated over 90%
                 of its producing properties.





                                       2
<PAGE>   3
         Over the last three years, Coho has implemented 12 secondary recovery
projects in the Mississippi salt basin.  Six of these projects have been
successfully developed and six are in the pilot phase.  Results from these
projects indicate that substantial opportunities exist for adding proved
reserves in fields owned by the Company.  The Company anticipates spending 25%
of its capital expenditure budget for 1997 on  secondary recovery projects.
Unlike traditional secondary recovery projects requiring large capital outlays,
Coho's projects typically have low capital costs, rapid production response and
low incremental operating costs because of the geologic characteristics of the
fields.

         On December 8, 1994, the Company acquired all of the capital stock of
Interstate Natural Gas Company ("ING").  ING, through its subsidiaries, was a
privately held natural gas producer, gatherer and pipeline company operating in
Louisiana and Mississippi.  As a result of the acquisition of ING, Coho
acquired approximately 86 BCF of natural gas reserves, with natural gas
production in December 1994 of 20 MMcf per day primarily from the Monroe field
in north Louisiana.  Additionally, the ING acquisition included approximately
1,000 miles of gathering systems in the Monroe field and a 167 mile long
interstate pipeline (operating as the Mid Louisiana Gas Company) and certain
intrastate pipeline facilities.

         Consideration paid by the Company for the acquisition of ING was $20
million cash, the assumption of net liabilities of $3.3 million (excluding
deferred taxes), 2,775,000 shares of the Common Stock and 161,250 shares of
redeemable preferred stock (which preferred shares were exchanged on August 30,
1995 for 3,225,000 shares of Common Stock), having an aggregate stated value of
$16,125,000.  The acquisition of ING was accounted for using the purchase
method.

         On April 3, 1996, ING sold all of the stock of three wholly-owned
subsidiaries that comprised its natural gas marketing and transportation
segment to an unrelated third party for cash of $19.5 million, the assumption
of net liabilities of approximately $2.3 million and the payment of taxes of
$1.2 million generated as a result of the tax treatment of the transaction.
The marketing and transportation segment is accounted for as discontinued
operations herein.

         The Company was incorporated in June 1993 under the laws of the State
of Texas and conducts a majority of its operations through its subsidiary Coho
Resources, Inc. ("CRI").  Prior to September 29, 1993, CRI was a publicly held
company of which Coho Resources Limited, a publicly held Alberta, Canada
company ("CRL"), held a 68% ownership interest.  As a result of a
reorganization of the Company effective on September 29, 1993, CRI and CRL
became wholly-owned subsidiaries of Coho Energy, Inc.

         References herein to "Coho" or the "Company", except as otherwise
indicated, refer to Coho Energy, Inc. and its subsidiaries, including CRI, CRL
and ING.  The Company's principal executive office is located at 14785 Preston
Road, Suite 860, Dallas, Texas 75240, and its telephone number is (972)
774-8300.

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 shall apply to the
technical terms used herein:

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

                 "Bcf" means billions of cubic feet.





                                       3
<PAGE>   4
                 "BOE" means barrel of oil equivalent, assuming a ratio of six
                 Mcf to one Bbl.

                 "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.

                 "Gross" means the number of wells or acres in which the
                 Company has an interest.

                 "Mbbls" means thousands of barrels.

                 "MBOE" means thousands of BOE.

                 "Mcf" means thousands of cubic feet.

                 "Mmbbls" means millions of barrels.

                 "MMBOE" means millions of BOE.

                 "Mmcf" means millions of cubic feet.

                 "Net"  is determined by multiplying gross wells or acres by
                 the Company's 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 reserves that exist behind the casing
                 of existing wells when the cost of making such reserves
                 available for production is relatively small relative to the
                 cost of a new well.

                 "Proved reserves or 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.

                 "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 whether or not such acreage contains proved
                 reserves.





                                       4
<PAGE>   5


                             OIL AND GAS OPERATIONS

EXPLORATION AND DEVELOPMENT ACTIVITIES

Principal Areas of Activity

         The following table sets forth, for Coho's major producing fields,
average net daily production of crude oil and natural gas on a BOE basis for
each of the three years ended December 31, 1996 and the number of productive
wells producing as of December 31, 1996, all of which are oil wells unless
otherwise indicated:

<TABLE>
<CAPTION>
                                                                                   YEAR ENDED DECEMBER 31                
                                                          ---------------------------------------------------------------
                                                                   1994                1995                   1996       
                                                          ------------------ --------------------------------------------
                                   GROSS          NET
                                PRODUCTIVE     PRODUCTIVE             % OF                  % OF                   % OF
FIELD                              WELLS         WELLS     BOE       TOTAL        BOE      TOTAL          BOE      TOTAL
-----                              -----         -----    ----       -----        ---      -----          ---    -------
<S>                                  <C>        <C>         <C>       <C>       <C>        <C>             <C>      <C>
Laurel, Mississippi . . . . .           35         32       3,100      54       3,470       38             3,317     34
Monroe, Louisiana (1) . . . .        2,749      2,649         280*      5       3,097       34             2,892     30
Summerland, Mississippi . . .           21         19       1,139      20       1,242       13             1,451     15
Soso, Mississippi . . . . . .           20         19         449       8         470        5               772      8
Martinville, Mississippi  . .           20         19         440       8         343        4               580      6
Brookhaven, Mississippi . . .           18         17         ---     ---         130**      1               416      4
Other (2) . . . . . . . . . .           23         14         314       5         453        5               341      3  
                                    ------      -----      -------    ---       -------   ----             -----    ---
Total . . . . . . . . . . . .        2,886      2,769       5,722     100       9,205      100             9,769    100
                                     =====      =====       =====     ===       =====      ===             =====    ===
</TABLE>

(1)      All gross and net wells located in Monroe, Louisiana are productive
         gas wells.
(2)      Of the wells indicated, 6 gross and 5 net wells are productive gas
         wells.

   *     Calculated as a 365 day average, however, production total represents
         volumes since the effective acquisition date (December 8, 1994).
   **    Calculated as a 365 day average, however, production total represents
         volume since the effective acquisition date (July 1, 1995).

         Laurel Field, Mississippi.  The Laurel field, a multi-pay geological
setting with producing horizons from the Eutaw formation of approximately 7,500
feet to the Hosston formation at approximately 13,500 feet, is the company's
largest oil producing property and represents approximately 34% of Coho's total
production on a BOE basis.  At December 31, 1996, the field contained 35 wells
producing from the Stanley, Christmas, Tuscaloosa, Washita-Fredricksburg,
Paluxy, Mooringsport, Rodessa, Sligo and Hosston Reservoirs.





                                       5
<PAGE>   6
         The Company considers the Laurel field an exploration and exploitation
success, as Coho  employed 3-D seismic in 1983 to initially define and develop
the multi-pay zones in the field, followed by a successful exploitation program
which included an extensive drilling program and more recently the
implementation of secondary recovery programs to increase production and
enhance ultimate reservoir recovery.  The field has multiple reservoirs with
varying drive mechanisms.  Coho's exploitation strategy is to continue
development of waterdrive reservoirs using primary recovery methods, while
employing secondary recovery in reservoirs with the characteristics of
depletion drive.

         In 1996 the Company continued  exploitation of the Laurel field by
implementing  secondary recovery projects in the Mooringsport, Rodessa, Sligo
and Tuscaloosa Stringer reservoirs.  The Company also drilled  five wells in
1996.  Three wells were drilled as successful high-angle or horizontal oil
producers in the Paluxy and Tuscaloosa reservoirs.  Two other wells were
drilled as service wells to enhance secondary recovery projects.  The Company
also established commercial production from the Washita-Fredricksberg formation
in 1996.  The average daily production in 1996 from the Laurel field was 3,317
BOE.  When compared to 1995, production  was down approximately 4.4 % in 1996
primarily as a result of the cyclic production function associated with the
secondary recovery project in the multi-layered Rodessa reservoir.  Each of
these sand layers will function as individual reservoirs and production will
cycle up and down as water breakthrough occurs in one sand layer and another
sand layer is pressured up.  This multi-layered reservoir has been modeled and
even though production declined in 1996, reserves were not adversely affected.
Proved oil reserves in the Laurel field have increased 5.3% since December 31,
1995 to 14.7 MMBOE.

         In addition to the continued exploitation program, much of the
Company's focus at Laurel during 1996 was directed toward a mineral leasing
program, permitting and surveying associated with shooting  a 37 square mile
3-D seismic program.  This program was completed during the fourth quarter of
1996 and the data is currently being processed.  This data will enhance the
Company's ability to further exploit primary and secondary reserves through
continued reservoir delineation.  Furthermore, the 3-D seismic program is
expected to enable evaluation of exploration potential both within and below
the defined productive limits of the field.  The currently defined commercial
limits of this large oil field encompass less than 700 acres (approximately 1.1
square miles).  The Company believes that the processed data will identify
several significant exploration opportunities that are within this 37 square
mile 3-D seismic shoot but outside the limits of Laurel field as defined today.

         Coho's average working interest is 91% in the 35 producing wells it
operates in the Laurel field.  Coho acquired its initial working interest in
1983 and became operator in 1987.

         Monroe Field, Louisiana.  In December 1994, as part of the ING
acquisition, the Company acquired a 98% working interest and operations in a
major portion of the Monroe field in Ouachita, Morehouse and Union parishes
Louisiana.  The field was discovered in 1916 and eventually encompassed 25
townships.  The primary producing horizon is at a depth of approximately 2,000
feet.  In 1996, the Company initiated a shallow Sparta gas sand exploitation
program which led to six new  shallow gas wells being drilled in the field at a
depth of 250 to 500 feet each.  This Sparta program, coupled with continued
operating efficiencies and improved gas prices, resulted in December 31, 1996
net proved reserves of 97.5 Bcf of gas in the Monroe field, a 4% increase over
December 31, 1995 proved reserves.  The field covers approximately 105,000
acres of fee mineral and leasehold acreage.





                                       6
<PAGE>   7
         As part of the ING acquisition the Company also acquired a 100%
interest in a natural gas gathering system located in the Monroe field in
Louisiana, as well as certain other gas gathering systems in the Gulf Coast
region.  These gathering systems, which are all Company-operated, consist of
over 1,000 miles of varying diameter pipe and 24 compressor units with a rated
capacity of approximately 11,800 horsepower.  In 1996, these systems gathered
approximately 28.9 Mmcf per day of Company-owned and third party gas.  These
gathering systems are operated through the Company's wholly owned subsidiaries,
Coho Louisiana Gathering Company ("CLGC") and Coho Fairbanks Gathering Company
("CFGC").

         Summerland Field, Mississippi.  The Summerland field, discovered in
1959, 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.

         Through various acquisitions since 1989, Coho acquired an average
89.6% working interest in this unitized field.  The Company assumed operating
control in November 1989.  Recompletions, development drilling and the
installation of higher volume artificial lift equipment increased net daily
crude oil production from 282 barrels in the first quarter of 1990 to 1,451
barrels in 1996.  1996 net daily crude oil production represents a 16.8%
increase over 1995 production and is also the highest  annual crude oil
production in the 38 year life of this oil field.  At December 31, 1996, the
Company operated 21 producing wells in this field.

         At December 31, 1996, the Summerland field had proved reserves of 5.8
MMBOE reflecting a 22% decline in reserves from year-end 1995.  This decline in
reserves was primarily associated with high production volumes during 1996 and
the drilling of two unsuccessful wells in the Tuscaloosa formation.

         Soso Field, Mississippi.  In mid-1990, the Company acquired a 90%
working interest in the Soso field.  The field was discovered in 1945 and
covers approximately 6,461 acres.  At December 31, 1996, the field  contained
20 producing crude oil wells.

         Soso is a multi-objective, underdeveloped field with low recovery
factors in the Rodessa, Hosston and Cotton Valley reservoirs, typical of
depletion drive reservoirs.  With positive results from  secondary recovery
efforts  in the Company's nearby Laurel and Martinville fields, the Company's
focus at Soso during 1994, 1995 and 1996 shifted toward waterflood
implementation.  In the last half of 1994, waterflood projects were initiated
in the Rodessa and Cotton valley formations utilizing existing wellbores.
Production response from these waterfloods, coupled with an active recompletion
program, has increased net daily production from 276 BOE in mid-1990 to a peak
of 772 net BOE in 1996.  1996 net daily production of 772 BOE represents a 64%
increase over 1995 production.  As of December 31, 1996, the Soso field had
proved reserves of 5.6 MMBOE, a 54% increase over year-end 1995 reserves.

         Martinville Field, Mississippi.  The Martinville field is located in
Simpson County, Mississippi and was originally discovered in 1957.  The Company
acquired its working interest and operating control in April 1989 and now owns
a 94% working interest.

         A 24 square mile 3-D seismic shoot was conducted in Martinville in
late 1995.  This seismic program was conducted to enhance the Company's ability
to exploit primary reserves through continued reservoir delineation as well as
develop full-scale secondary recovery projects in the Mooringsport, Rodessa and
Sligo formations.  During 1996 the Rodessa and Sligo reservoirs were delineated
through





                                       7
<PAGE>   8
drilling and a full scale water flood was initiated in the Rodessa reservoir
with favorable results.   The secondary recovery development portion of the
1996 program included the drilling of 7 new wells, 4 service wells and 3
producers.  The 3-D seismic data was also utilized in 1996 to drill two
exploration wells, one of which was a success in the Hosston and Sligo
formations.

         In 1997 the Company plans to utilize the 3-D seismic to delineate the
Mooringsport reservoir and to fully develop this secondary recovery project.
The 3-D data set is currently being reprocessed to more clearly define the
deep, Hosston, Cotton Valley and Smackover exploration objectives.  The Company
believes significant exploration opportunities, both shallow and deep, will
follow in 1997 and beyond.  As a result of the initial response from the
Rodessa secondary recovery project and exploration success, the Company's
average net daily production in Martinville increased to 580 net BOE in 1996, a
69% increase over 1995 production.

         The Martinville field is characterized by highly complex faulting,
similar to the Laurel field and like the Laurel field produces from numerous
horizons.  Proved reserves in the Martinville field have increased 57% since
December 31, 1995 to 4.6 MMBOE as of December 31, 1996.

         Brookhaven Field, Mississippi.  In August 1995, the Company acquired
93% of a unitized field containing 11 active wells and 159 inactive wells near
Brookhaven, Mississippi.  At the date of acquisition, the estimated total net
proved reserves were 1.2 MMBOE with production averaging approximately 230 net
BOE per day in July 1995.

         The Brookhaven field has characteristics similar to those of other
Coho properties and, as a result, the Company began development of the
properties shortly after the acquisition.  In 1996, much of the Company's focus
for Brookhaven was directed at fully understanding the depositional environment
for this large, stratigraphically complex Tuscaloosa oil formation.  Detailed
sand mapping coupled with past production history, led to the Company drilling
five new Tuscaloosa penetrations from existing wellbores in 1996.  These five
penetrations found unswept oil reserves associated with structural and
stratigraphic complexity.  Three of these penetrations were completed as
commercial producers and two will be utilized as injectors to recommence
waterflood operations.  In addition, in 1996 the Company identified both
shallow and deep exploration potential at Brookhaven.

         Proved reserves in the Brookhaven field have increased 63% since
year-end 1995 to 2.9 MMBOE as of December 31, 1996.  Daily net production has
increased to approximately 416 net BOE in 1996.

         Other Properties.  The Company has working interests in other
producing properties in Mississippi and Texas.  Coho operates the Bentonia and
Frio properties in Mississippi, and the Round Prairie property in Texas.
Additionally, Coho  owns non-operated working interests in the Glazier property
in Mississippi and the North Padre A-59 Block offshore Texas in the Gulf of
Mexico.  As of December 31, 1996, these fields had combined net proved reserves
of 3.8 MMBOE.

         Tunisia, North Africa.  During 1994, Coho and its joint interest
partners conducted a seismic survey on both the Anaguid and Alyane permits in
Tunisia.  In October 1995, Coho and its partners commenced drilling the first
exploratory well (BZN #1) on its Anaguid  permit in southern Tunisia.  In early
1996, the well reached total depth and was plugged and abandoned after finding
the objective zones to be nonproductive.  Coho is currently evaluating other
potential opportunities in the permit area.  The





                                       8
<PAGE>   9
Company's current working interest is 50% in the Anaguid permit and 100% in the
Alyane permit (up from 50% in 1995 due to the non-renewal of a 50% option by a
third party).


Production

         The following table sets forth certain information regarding Coho's
volumes, average prices received and average production costs associated with
its sales of crude oil and natural gas for each of the three years ended
December 31, 1996:

<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31   
                                                           ---------------------------
                                                              1994        1995      1996
                                                              ----        ----      ----
<S>                                                           <C>        <C>      <C>
Crude Oil
   Volumes (Mbbls)  . . . . . . . . . . . . . . . . . .        1,976      2,178     2,468
   Average sales price ($/Bbl)(1) . . . . . . . . . . .       $12.86     $13.62    $16.42

Natural Gas
   Volumes (MMcf) . . . . . . . . . . . . . . . . . . .       670(2)      7,092     6,646
   Average sales price ($/Mcf)(3) . . . . . . . . . . .       $ 1.55      $1.59     $2.07

Average Production Cost ($/BOE)(4)  . . . . . . . . . .       $ 4.49      $3.71     $3.88
</TABLE>
-----------------------

(1)      Includes the effects of oil price hedging contracts. Price per Bbl
         before the effect of hedging was  $12.32, $13.89 and $18.34 for the
         years ended December 31, 1994, 1995 and 1996, respectively.

(2)      Includes volumes from ING properties for the one month post
         acquisition period.

(3)      Includes the effects of gas price hedging contracts.  Price per Mcf
         before the effect of hedging was  $1.55, $1.44 and $2.24 for the years
         ended December 31, 1994, 1995 and 1996, respectively.

(4)      Includes lease operating expenses and production taxes.





                                       9
<PAGE>   10
Drilling Activities

         During the periods indicated, the Company drilled or participated in
the drilling of the following wells, all of which were in the United States,
except as otherwise indicated.

<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31                 
                               --------------------------------------------------------------
                                    1994                  1995                  1996
                                    ----                  ----                  ----
                               GROSS        NET       GROSS       NET       GROSS         NET 
                               -----        ---       -----       ---       -----         ---
<S>                              <C>         <C>       <C>        <C>        <C>        <C>
Wells Drilled

   Exploratory
     Crude Oil  . . . .          ---         ---       ---        ---          1         1.0
     Natural Gas  . . .          ---         ---       ---        ---        ---         ---
     Dry Holes  . . . .            1         0.3         1*       0.5*         1         1.0
   Development  . . . .
     Crude Oil  . . . .            4         3.7         6        5.4         13        12.0
     Natural Gas  . . .          ---         ---         1        1.0          6         6.0
     Dry Holes  . . . .          ---         ---       ---        ---          4         3.7
     Service Wells  . .            2         1.7         1         .9          8         7.5
                                 ---         ---       ---        ---         --        ----
Total                              7         5.7         9        7.8         33        31.2
                                 ===         ===       ===        ===         ==        ====
</TABLE>                                               
-----------------------------------------------------------------------------
   *     Well drilled in Tunisia

Reserves
         The following table summarizes the Company's net proved crude oil and
natural gas reserves by field as of December 31, 1996, which have been reviewed
by Ryder Scott Company Petroleum Engineers, independent petroleum engineers.
<TABLE>
<CAPTION>
                                                       OIL             GAS       NET PROVED
                                                      MBBLS            MMCF       RESERVES
                                                      -----            ----       --------
                                                                                    (MBOE)
                                                                                    ------
<S>                                                  <C>            <C>              <C>
Laurel, Mississippi . . . . . . . . . . .            14,573             463          14,650
Monroe, Louisiana . . . . . . . . . . . .             --             97,545          16,257
Summerland, Mississippi . . . . . . . . .             5,849           --              5,849
Soso, Mississippi . . . . . . . . . . . .             5,640           --              5,640
Martinville, Mississippi  . . . . . . . .             4,490             652           4,599
Brookhaven, Mississippi . . . . . . . . .             2,803             316           2,855
Other . . . . . . . . . . . . . . . . . .             1,467          14,156           3,828
                                                     ------         -------          ------
Total . . . . . . . . . . . . . . . . . .            34,822         113,132          53,678
                                                     ======         =======          ======
</TABLE>





                                       10
<PAGE>   11
         At December 31, 1996, the Company had proved developed reserves of
40,579 MBOE and proved undeveloped reserves of 13,099 MBOE.  The Present Value
of Proved Reserves was $417.1 million, which represented $299.3 million for the
proved developed and $117.8 million for the proved undeveloped reserves. At
December 31, 1995, the Company reported total proved reserves of 48,777 MBOE
and the Present Value of Proved Reserves was $268.6 million.  This represents
an increase of 4,901 MBOE and $148.5 million in reserves and Present Value of
Proved Reserves, respectively, at December 31, 1996.  The increase was
attributable to extensions and discoveries associated with the Company's
efforts in Mississippi, the increase in posted crude oil prices and increased
natural gas prices, as well as a new crude oil marketing contract which reduced
the spread between the actual price received by Coho for its crude oil and
posted prices.

         There are numerous uncertainties inherent in estimating quantities of
proved crude oil and natural gas reserves, including many factors beyond the
control of the Company.  The estimates of the reserve engineers are based on
several assumptions, all of which are to some degree speculative.  Actual
future production, revenues, taxes, production costs, development expenditures
and quantities of recoverable crude oil and natural gas reserves might vary
substantially from those assumed in the estimates.  Any significant variance in
these assumptions could materially affect the estimated quantity and value of
reserves set forth herein.  In addition, the Company's reserves might be
subject to revision based upon actual production, results of future
development, prevailing crude oil and natural gas prices and other factors.

         In general, the volume of production from crude oil and natural gas
properties declines as reserves are depleted. Except to the extent Coho
acquires additional properties containing proved reserves or conducts
successful exploration and development activities, or both, the proved reserves
of Coho will decline as reserves are produced.  Future crude oil and natural
gas production is, therefore, highly 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 of operations from producing activities, see
"Supplemental Information Related to Oil and Gas Activities" appearing in note
16 to the consolidated financial statements of the Company.





                                       11
<PAGE>   12

Acreage

         The following table summarizes the developed and undeveloped acreage
owned or leased by Coho at December 31, 1996:

<TABLE>
<CAPTION>
                                                                     ACREAGE
                                                                     -------
                                                    DEVELOPED                    UNDEVELOPED
                                                    ---------                    -----------
                                                    GROSS        NET             GROSS        NET
                                                    -----        ---             -----        ---
<S>                                               <C>         <C>               <C>         <C>
Mississippi . . . . . . . . . . . . . . . .        25,126      23,167           12,153      12,115
Louisiana . . . . . . . . . . . . . . . . .       125,770     105,496            1,598       1,419
Texas . . . . . . . . . . . . . . . . . . .         2,796       2,796            1,691       1,691
Offshore Gulf of Mexico . . . . . . . . . .         5,760       2,269              ---         ---
                                                  -------     -------           ------      ------
Total . . . . . . . . . . . . . . . . . . .       159,452     133,728           15,442      15,225
                                                  =======     =======           ======      ======
</TABLE>


         The Company also holds a working interest in two exploratory permits
in Tunisia, North Africa; an onshore permit covering 1,412,000 gross acres (50%
working interest) and an offshore permit covering 115,000 gross acres (100%
working interest).

Title to Properties

         As is customary in the oil and gas industry, in certain circumstances,
the Company makes only a limited  review of title to undeveloped oil and gas
leases at the time they are acquired by Coho.  However, before the Company
acquires oil and gas properties, and before drilling commences on any leases,
the Company causes a thorough title search to be conducted, and any material
defects in title are remedied.  To the extent title opinions or other
investigations reflect title defects, the Company, rather than the seller of
the undeveloped property, is typically obligated to cure any such title defects
at its expense.  If Coho were unable to remedy or cure any title defect of a
nature such that it would not be prudent to commence drilling operations on the
property, the Company could suffer a loss of its entire investment in the
property.  The Company believes that it has good title to its oil and gas
properties some of which are subject to immaterial encumbrances, easements and
restrictions.  The oil and gas properties owned by the Company are also
typically subject to royalty and other similar non-cost bearing interests
customary in the industry.  The Company does not believe that any of these
encumbrances or burdens will materially affect Coho's ownership or use of its
properties.


DISCONTINUED OPERATIONS

         On April 3, 1996, ING sold all of the stock of its three wholly-owned
subsidiaries that comprise the Company's natural gas marketing and
transportation segment for a total consideration of approximately $23 million
to an unrelated third party.  The consideration paid was $19.5 million cash at
closing, the assumption of net liabilities of approximately $2.3 million and
reimbursement for the payment of taxes of $1.2 million, generated as a result
of the tax treatment of the transaction.  The natural gas marketing and
transportation segment is accounted for as discontinued operations herein.





                                       12
<PAGE>   13
COMPETITION

         The crude oil and natural gas industry is highly competitive. A large
number of companies and individuals engage in drilling for crude oil and
natural gas, and there is a high degree of competition for crude oil and
natural gas properties suitable for drilling and for materials and third-party
services essential for their exploration and development. The principal
competitive factors in the acquisition of crude oil and natural gas properties
include the staff and data necessary to identify, investigate and purchase such
properties and the financial resources necessary to acquire and develop them.
Many of Coho's competitors are substantially larger and have greater financial
and other resources than does Coho.

         The principal resources necessary for the exploration for, and the
acquisition, exploitation,  production and sale of, crude oil and natural gas
are leasehold or freehold prospects under which crude oil and natural gas
reserves may be discovered, drilling rigs and related equipment to explore for
and develop such reserves, casing and other capital assets required for the
exploitation  and production of the reserves and knowledgeable personnel to
conduct all phases of crude oil and natural gas operations. Coho must compete
for such resources with both major oil companies and independent operators and
also with other industries for certain personnel and materials. Although Coho
believes its current resources are adequate to preclude any significant
disruption of operations in the immediate future, the continued availability of
such materials and resources to Coho cannot be assured.

CUSTOMERS AND MARKETS

         Substantially all of Coho's crude oil is sold at the wellhead at
posted prices, as is the custom in the industry. In certain circumstances,
natural gas liquids are removed from the natural gas produced by Coho and are
sold by Coho at posted prices.  During the year ended December 31, 1996, two
purchasers of Coho's crude oil and natural gas, EOTT Energy Corp. ("EOTT") and
Mid Louisiana Marketing Company, accounted for 66% and 15%, respectively, of
Coho's receipt of operating revenues.  In 1995 Amerada Hess Corporation
("Amerada") accounted for 66% of Coho's receipt of operating revenues.
Subsequent to December 31, 1995, Amerada sold its Mississippi pipeline
transportation and marketing assets to EOTT.  Coho consented to Amerada's
assignment of its short term contract to EOTT and entered into a new three-
year crude oil  purchase agreement with EOTT effective March 1, 1996.  Under
the crude purchase agreement Coho has committed the majority of its crude oil
production in the State of Mississippi to EOTT for a period of three years on a
pricing basis of posting plus a premium.

         The natural gas produced in the Monroe Field has historically been
either sold to industrial customers in the field  that are connected to the
gathering system (approximately 17,350 Mcf per day of company produced gas in
1996), or is sold  to industrial or jurisdictional customers along the
interstate pipeline formerly owned by the Company .  Generally, the Company
sells its gas production at prices based on regional price indices, set on a
month to month basis.  Effective with the sale of the natural gas marketing and
transportation companies, the Company entered into a long-term gas sales
contract for  its Monroe field gas to Mid Louisiana Marketing Company based on
regional price indices set on a month-to-month basis, consistent with past
operations.

           The price received by the Company for oil and gas may vary
significantly during certain times of the year due to the volatility of the oil
and gas market, particularly during the colder winter and hot summer months.
As a result, the Company periodically  enters into forward sale agreements or
other





                                       13
<PAGE>   14
arrangements for a portion of its crude oil and natural gas production to hedge
its exposure to price fluctuations.  Gains and losses on these forward sale
agreements are reflected in crude oil and natural gas revenues at the time of
sale of the related hedged production. While intended to reduce the effects of
the volatility of the prices received for crude oil and natural gas, such
hedging transactions may limit potential gains by the Company if crude oil and
natural gas prices were to rise substantially over the price established by the
hedge.  See Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Results of Operations and Note 1 to the Consolidated
Financial Statements.

OFFICE AND FIELD FACILITIES

         The Company leases its executive and administrative offices in Dallas,
Texas, consisting of 33,261  square feet, under a lease that continues through
October  2000.  The Company also leases a field office in Laurel, Mississippi
covering approximately  5,000 square feet, under a non-cancelable lease
extending through June, 2000.  The field office facilities in Fairbanks,
Louisiana and Brookhaven, Mississippi are owned by the Company.

GOVERNMENTAL REGULATION

         Regulation of Oil and Gas Exploration and Production.  Oil and gas
exploration, development and production are subject to various types of
regulation by local, state and federal agencies.  Such regulations include
requiring permits for the drilling of wells, maintaining bonding requirements
in order to drill or operate wells, and regulating the location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled, and the plugging and abandonment of
wells.  The Company's operations are also subject to various conservation laws
and regulations, including those of Mississippi, Louisiana and Texas wherein
the Company's properties are located.  These laws and regulations include the
regulation of the size of drilling and spacing units or proration units, the
density of wells that may be drilled, and unitization or pooling of oil and gas
properties.  In this regard, some states allow the forced pooling or
integration of tracts to facilitate exploration while other states rely on
voluntary pooling of land and leases.  In addition, state conservation laws
establish maximum rates of production from crude oil and natural gas wells,
generally restrict the venting or flaring of gas, and impose certain
requirements regarding the ratability of production.  The effect of these
regulations is to limit the amount of crude oil and natural gas the Company can
produce from its wells and to limit the number of wells or the locations at
which the Company can drill.  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, the Company is subject to production tax rates of up to 6% in
Mississippi and $0.02 per Mcf in Louisiana.  In addition, the Company has been
active in the adoption of legislation dealing with production and severance tax
relief in Mississippi.

         Legislation affecting the oil and gas industry is under constant
review for amendment and expansion.  Also, numerous departments and agencies,
both federal and state, are authorized by statute to issue and have issued
rules and regulations binding on the oil and gas industry and its individual
members, some of which carry substantial penalties for failure to comply.  The
regulatory burden on the oil and gas industry increases the Company's cost of
doing business and, consequently, affects its profitability.

         Offshore Leasing.  Some of the Company's operations are located on
federal oil and gas leases, which are administered by the United States
Minerals Management Service (the "MMS").  Such leases are issued through
competitive bidding, contain relatively standardized terms and require
compliance with detailed MMS regulations and orders (which are subject to
change by the MMS).  For offshore





                                       14
<PAGE>   15
operations, lessees must obtain MMS approval for exploration plans and
development and production plans prior to the commencement of such operations.
In addition to permits required from other agencies (such as the Coast Guard,
the Army Corps of Engineers and the Environmental Protection Agency), lessees
must obtain a permit from the MMS prior to the commencement of drilling.  The
MMS has promulgated regulations requiring offshore production facilities
located on the Outer Continental Shelf ("OCS") to meet stringent engineering
and construction specifications.  Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore
and the removal of all production facilities.  Under certain circumstances, the
MMS may require any Company operations of federal leases to be suspended or
terminated.  To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable
assurances that such obligations will be met.  The cost of such bonds or other
surety can be substantial and there is no assurance that the Company can obtain
bonds or other surety in all cases.

         In addition, the U.S. Court of Appeals, D.C. Circuit recently ruled
that the MMS can only collect royalties on gas that is produced, bought or
sold, and cannot collect revenues from financial arrangements, such as
take-or-pay settlements.

         In 1995, the MMS issued a notice of proposed rulemaking in which it
proposes to amend its regulations governing the calculation of royalties and
the valuation of natural gas produced from federal leases.  The principal
feature in the amendments, as proposed, would establish an alternative market
index based method to calculate royalties on certain natural gas production
sold to affiliates or pursuant to non-arm's-length sales contracts.  The MMS
has proposed this rulemaking to facilitate royalty valuation in light of
changes in the gas marketing environment.  The MMS reopened the public comment
period under the proposed rule due to the diversity of comments received under
the proposed rule.  As a result, the MMS outlined five options for alternatives
to using gross proceeds as a basis for gas valuation.  In 1996, the MMS
proposed a rulemaking to update transportation allowance regulations to reflect
the changes in the natural gas industry due to FERC Order No. 636 unbundling.
The rulemaking would clarify which costs are deductible from federal and Indian
leases.  The Final Rule is expected this year.  The Company cannot predict what
action the MMS will take on these matters, nor can it predict at this stage of
the rulemaking proceeding how the Company might be affected by amendments to
the regulations.

         Oil Sales and Transportation Rates.  Sales of crude oil and condensate
can be made by Coho at market prices not subject at this time to price
controls.  In January 1997, the MMS proposed a rulemaking to modify the
valuation procedures for arm's length and non-arm's-length oil transactions.
The intent of the rule is to decrease the reliance on posted prices and assign
a value to crude oil that better reflects market value.  Comments on this
proposed rulemaking are due by March 25, 1997.  The price that the Company
receives from the sale of these products is affected by the cost of
transporting the products to market.  The Energy Policy Act of 1992 directed
the FERC to establish a "simplified and generally applicable" rate making
methodology for oil pipeline rates.  Effective as of January 1, 1995, the FERC
implemented regulations establishing an indexing system for transportation
rates for oil pipelines, which would generally index such rates to inflation,
subject to certain conditions and limitations.  The Company is not able to
predict with certainty what effect, if any, these regulations will have on it,
but other factors being equal under certain conditions, the regulations may
tend to increase transportation costs or reduce wellhead prices for such
commodities.

         Gathering Regulation.  Under the Natural Gas Act (the "NGA"),
facilities used for and operations involving the production and gathering of
natural gas are exempt from FERC jurisdiction, while facilities used for and
operations involving interstate transmission are not.  The FERC's determination
of what constitutes exempt gathering facilities, as opposed to jurisdictional
transmission





                                       15
<PAGE>   16

facilities, has evolved over time.  Under current law even facilities which
otherwise would have been classified as gathering may be subject to the FERC's
rates and service jurisdiction when owned by an interstate pipeline company and
when such regulation is necessary in order to effectuate FERC's Order No. 636
open-access initiatives.  Respecting facilities owned by noninterstate pipeline
companies, such as Coho Fairbanks Gathering Company (CFGC)  and Coho Louisiana
Gathering Company (CLGC), the Company's gathering facilities, the FERC has
historically distinguished between these types of activities on a very
fact-specific basis which makes it difficult to predict with certainty the
status of gathering facilities.  On November 1, 1993, in Docket No.
CP93-79-000, this uncertainty was settled by FERC with respect to the gathering
facilities transferred from Mid Louisiana Gas Company, the Company's former
interstate pipeline, to CFGC effective January 1, 1994, when FERC issued an
order declaring the facilities to be nonjurisdictional gathering.  On May 27,
1994, FERC affirmed its November 1, 1993 order in all material respects.  On
June 27, 1994, the Producer-Marketer Transportation Group Gathering Coalition
and the Independent Petroleum Association of America (IPAA) filed a request for
a rehearing of the May 27, 1994 order.  On December 6, 1994, FERC issued a
final order disallowing IPAA's request for rehearing.  On December 9, 1994,
IPAA filed a petition for review of the FERC orders in the U.S. Court of
Appeals, D.C. Circuit.  This case is one in a series of cases that has
delineated the FERC's gathering policy.  Among other matters, the FERC slightly
narrowed its statutory tests for establishing gathering status and reaffirmed
that it does not have jurisdiction over natural gas gathering facilities and
services and that such facilities and services are properly regulated by state
authorities.  As a result, natural gas gathering may receive greater regulatory
scrutiny by state agencies.  In addition, the FERC has approved several
transfers by interstate pipelines of gathering facilities to unregulated
gathering companies, including affiliates.  This could allow such companies to
compete more effectively with independent gatherers.  Although these FERC
orders delineating its new gathering policy are subject to court appeals, there
has been only one definitive court decision to date.  The U.S. Court of
Appeals, D.C. Circuit upheld the FERC's decision to not regulate gathering
rates but found that its "default" contract requirement was unlawful as outside
the FERC's jurisdiction.  The court remanded the case to the FERC, which has
not yet acted on remand.  The U.S. Supreme Court declined to review the D.C.
Circuit's decision.  Management does not believe the ultimate resolution of
these proceedings will have a material adverse effect on the financial
condition of the company.

         State regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances, nondiscriminatory take
requirements.  While some states provide for the rate regulation of pipelines
engaged in the intrastate transportation of natural gas, such regulation has
not generally been applied against gatherers of natural gas.  For historical
reasons, however, certain of the gathering facilities owned by CLGC are subject
to the jurisdiction of the Louisiana Department of Natural Resources ("LDNR")
pursuant to its authority to regulate intrastate pipelines.  Further, natural
gas gathering may receive greater regulatory scrutiny following the pipeline
industry restructuring under Order No. 636.   Thus the Company's gathering
operations could be adversely affected should they  be subject in the future to
the application of state or federal regulation of rates and services.

         Future Legislation and Regulation.  The Company's operations will be
affected from time to time in varying degrees by political developments and
federal and state laws and regulations.  In particular, oil and gas production
operations and economics are affected by tax and other laws relating to the
petroleum industry, by changes in such laws and by constantly changing
administrative regulations.  For example, the price at which natural gas may
lawfully be sold has historically been regulated under the NGA.  Only recently,
with the deregulation of the last regulated price categories of natural gas on
January 1, 1993, have free market forces been allowed to control the sales
price of natural gas.  Given the right set of circumstances, there is no
guarantee that new regulations, similar or otherwise, would not be imposed on
the production or sale of oil, condensate or gas.  It is therefore impossible
to predict the





                                       16
<PAGE>   17
terms of any future legislation or regulations that might ultimately be enacted
or the effects of any such legislation or regulations on the Company.


ENVIRONMENTAL REGULATIONS

         The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection.  These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the types,
quantities and concentration of various substances that can be released into
the environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wildlife
refuges or preserves, wetlands and other protected areas, and impose
substantial liabilities for pollution resulting from the Company's operations.
Changes in environmental laws and regulations occur frequently, and any changes
that result in more stringent and costly waste handling, disposal and clean-up
requirements could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general.  Management believes
that the Company is in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements will not have a material adverse impact on the Company.

         The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of regulations on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills
in "waters of the United States". A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located.  The term "waters of the United States"
has been broadly defined to include inland waterbodies, including wetlands,
playa lakes, and intermittent streams.  The OPA as recently amended, requires
the lessee or permittee of the offshore area in which an oil or natural gas
facility is located to establish and maintain evidence of financial
responsibility in the amount of $35.0 million to cover liabilities related to
an oil spill for which such person is statutorily responsible.  Prior to its
amendment, the OPA required such lessee or permittee to maintain evidence of
financial responsibility in the amount of $150.0 million, and the amended
statute authorizes the President of the United States to increase the amount of
financial responsibility to $150.0 million depending on the risks posed by the
quantity of oil that is handled by the facility.  The MMS, before the amendment
of the OPA, published an advance notice of its intention to adopt regulations
implementing the OPA's financial responsibility requirements for offshore
facilities, and it is probable that the MMS will proceed with the promulgation
of such regulations under the amended statute.  The Company cannot predict the
final form of any financial responsibility regulations that will be adopted by
the MMS, but the impact of any such regulations should not be any more adverse
to the Company than it will be to other similarly situated companies.

         The OPA also imposes other requirements on responsible parties, such
as the preparation of an oil spill contingency plan. The Company has such a
plan in place.  Failure to comply with the OPA's ongoing requirements or
inadequate cooperation during a spill event may subject a responsible party to
civil or criminal enforcement actions.  As of this date, the Company is not the
subject of any civil or criminal enforcement actions under the OPA.

         The Comprehensive Environmental Response, Compensation, and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons that are considered to have contributed to the release of a "hazardous
substance" into the environment.  These persons include the owner or operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site.  Persons who are or were responsible for releases of hazardous substance
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances
released into the environment.   Currently, the Company does not own or operate
CERCLA identified sites.





                                       17
<PAGE>   18
         A significant portion of the Company's operations in Mississippi are
conducted within city limits.  On an annual basis in order to obtain permits to
conduct new drilling operations, the Company is required to meet certain tests
of financial responsibility.  The Company is conducting a voluntary program to
remove inactive aboveground storage tanks from its well sites.

         Certain governmental agencies are presently studying whether the oil
and gas industry's practice of utilizing mercury meters poses any potential
problems that require more stringent regulation.  Operators in the Monroe Field
have been asked to monitor their operations and assist in gathering data.
During 1995, the Company voluntarily negotiated a remediation plan with the
governmental agencies responsible for the two wildlife refuges in the Monroe
Field.  Under the plan, the Company began removal of the mercury meters within
the two wildlife refuges in 1996.  The Company continues to cooperate  with the
other various agencies in their studies.  At this time, the Company believes
that minor mercury spillages and leaks may have occurred in the past.  However,
the Company believes that such spillages and leaks are less than the amounts
reportable under prior or existing statues and laws.  The Company makes a
provision for future site restoration charges on a unit-of-production basis
which is included in depletion and depreciation expense.

         Because the Company's strategy is to acquire interests in
underdeveloped oil and gas properties many of which have been operated by
others for many years, the Company may be liable for damage or pollution caused
by the former operators of such oil and gas properties.  The Company's
operations are also subject to all of the risks normally incident to the
operation and development of oil and gas properties and the drilling of oil and
gas wells, including encountering unexpected formations or pressures, blowouts,
cratering and fires, which could result in personal injuries, loss of life,
pollution damage and other damage to the properties of the Company and others.
Moreover, offshore operations are subject to a variety of operating risks
peculiar to the marine environment, such as hurricanes or other adverse weather
conditions, to more extensive governmental regulation, including regulations
that may, in certain circumstances, impose strict liability for pollution
damage, and to interruption or termination of operations by governmental
authorities based on environmental or other considerations.  The Company
maintains insurance against certain losses or liabilities arising from its
operations in accordance with customary industry practices and in amounts that
management believes to be reasonable.  However, insurance is either not
available to the Company against all operational risks or is not economically
feasible for the Company to obtain.  The occurrence of a significant event that
would impose liability on the Company that is either not insured or not fully
insured could have a material adverse effect on the Company's financial
condition and results of operations.

EMPLOYEES

         At February 1, 1997, Coho had 134 employees associated with its
operations, including 27 field personnel in Mississippi and 40 field personnel
in Louisiana.  The Company considers its employee relations to be good.





                                       18
<PAGE>   19

ITEM 2.  PROPERTIES

         For information with respect to the Company's properties, see
"Business and Properties".


ITEM 3.  LEGAL PROCEEDINGS

          In July, 1994, the Company, together with several other companies,
was named as a defendant in a lawsuit filed in Jones County, Mississippi.  The
lawsuit involves claims by a landowner for purported damages caused by
naturally occurring radioactive materials at various wellsite locations on land
leased by the Company in Mississippi.  The plaintiff is seeking significant
compensatory and punitive damages, including damages for "emotional distress".
This lawsuit has been dormant for two years and the land involved has been
remediated.

         Additionally, in 1996 the Company, together with several other
companies, was named as a defendant in a number of lawsuits of the same nature
as the July, 1994 lawsuit.  All of the suits are principally identical and seek
damages for land damage, health hazard, mental and emotional distress, etc.
None of the suits seek specific award amounts, but all seek punitive damages.

         In January 1996, the Company was named a defendant in a lawsuit filed
in the Circuit Court of Jasper County, Mississippi.  The lawsuit stems from the
accidental death of an employee of an independent contractor doing work for the
Company in late 1995.  The plaintiffs are seeking compensatory and punitive
damages.  A subsequent lawsuit was filed by another employee of the independent
contractor for injuries allegedly sustained during the accident.

         While the Company is not able to determine its exposure in the
remaining suits at this time, the Company believes that the claims will have no
material adverse effect on its financial position or results of operations.

         The Company is involved in various other legal actions arising in the
ordinary course of business.  While it is not feasible to predict the ultimate
outcome of these actions or those listed above, management believes that the
resolution of these matters will not have a material adverse effect, either
individually or in the aggregate, on the Company's financial position or
results of operations.


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

         No matters were submitted to a vote of security holders during the
fourth quarter of 1996.





                                       19
<PAGE>   20
                                    PART II

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

         The Company's Common Stock is traded on the Nasdaq Stock Market under
the symbol "COHO" and on the Toronto Stock Exchange under the symbol "CEE".
The following table sets forth the range of high and low sale prices for the
Common Stock as reported on the Nasdaq Stock Market.

<TABLE>
<CAPTION>
                                                                         HIGH               LOW
                                                                         ----               ---
<S>              <C>                                                  <C>            <C>
1995
                 1st Quarter  . . . . . . . . . . . . . . . .         $   5 1/2      $   4 23/32
                 2nd Quarter  . . . . . . . . . . . . . . . .             6 1/8          4 7/8
                 3rd Quarter  . . . . . . . . . . . . . . . .             5 9/16         4 7/16
                 4th Quarter  . . . . . . . . . . . . . . . .             5 3/8          4  1/2
1996
                 1st Quarter  . . . . . . . . . . . . . . . . .           6 5/8          4 5/8
                 2nd Quarter  . . . . . . . . . . . . . . . . .           7 1/8          5 15/16
                 3rd Quarter  . . . . . . . . . . . . . . . . .           7 1/2          6 1/8
                 4th Quarter  . . . . . . . . . . . . . . . . .           8 1/4          6 3/4
</TABLE>

--------------------------------                                             
         The last reported sale price of the Common Stock as reported on the
Nasdaq Stock Market on February 28, 1997 was $7.875 per share.  At February 28,
1997, there were 173 holders of record of the Common Stock. The Company
believes it has in excess of 900 beneficial holders of its Common Stock.


         The Company has never paid cash dividends on its Common Stock and does
not intend to pay cash dividends on its Common Stock in the foreseeable future.
In the past, the Company has used its available cash flow to conduct
exploration and development activities or to make acquisitions, and expects to
continue to do so in the future.  In addition, the terms of the Company's
revolving credit facility restrict the payment of dividends by the Company and
CRI.  Coho Energy, Inc. currently is a holding company with no independent
operations.  Accordingly, any amounts available for dividends will be dependent
on the prior declaration of dividends by CRI or CRL to Coho Energy, Inc.  Any
declaration of dividends by CRI or CRL would be subject to Canadian or U.S.
withholding tax at applicable tax rates.

         On December 9, 1996, the Company issued 100,000 shares of Common Stock
to Churchill Resource Investments, Inc., a Colorado corporation, in
consideration for certain oil and gas properties and interests in the Laurel
and Glazier, Mississippi fields.  The shares were issued without registration
under the Securities Act of 1933, as amended (the "Act"), in reliance on the
exemption therefrom set forth in Section 4(2) of the Act.





                                       20
<PAGE>   21
ITEM 6.                     SELECTED FINANCIAL DATA

         The following selected consolidated financial data for each of the
five years in the period ended December 31, 1996 are derived from, and
qualified by reference to, the Company's audited consolidated financial
statements included at Item 8 hereof. The information presented below should
be read in conjunction with Coho's Consolidated Financial Statements and the
notes thereto and Item 7 "Management's Discussion and Analysis of Financial
Condition and Results of Operations" included elsewhere herein.  The selected
consolidated financial data presented below are not necessarily indicative of
the future results of operations or financial performance of the Company.


<TABLE>
<CAPTION>
                                                             1992        1993      1994(1)     1995       1996
                                                             ----        ----      -------     ----       ----
                                                                (in thousands, except per share amounts)
<S>                                                        <C>         <C>                   <C>       <C>
STATEMENT OF EARNINGS DATA: (2)
         Operating revenues   . . . . . . . . . . . . .    $26,915     $28,263    $26,464    $40,903    $54,272
         Operating costs  . . . . . . . . . . . . . . .      7,250       8,773      9,372     12,457     13,875
         General and administrative expenses  . . . . .      2,779       2,997      3,435      5,400      7,264
         Depletion and depreciation . . . . . . . . . .      7,773      10,677      9,989     14,717     16,280
         Net interest expense   . . . . . . . . . . . .      3,146       3,484      3,972      8,048      7,464
         Other expense (3)  . . . . . . . . . . . . . .        ---      21,000        973        ---        ---
         Income tax expense (benefit) . . . . . . . . .      2,330      (5,219)      (303)       112      3,483
         Earnings (loss) from continuing operations . .      3,637     (13,449)      (974)       169      5,906
         Net earnings (loss)  . . . . . . . . . . . . .      3,637     (13,449)    (1,654)     1,780      5,906
         Net earnings (loss) from continuing
           operations per common share(4)   . . . . . .      $0.31      $(1.12)    $(0.07)     $(.02)      $.29
         Net earnings (loss) per common share(4)  . . .      $0.31      $(1.12)    $(0.12)     $ .05       $.29

OTHER FINANCIAL DATA: (2)
         Capital expenditures . . . . . . . . . . . . .    $26,341     $24,122    $19,503    $29,970    $52,384

BALANCE SHEET DATA: (2)
         Working capital (deficit) (5)  . . . . . . . .     $1,790        $871    $(2,379)   $14,433     $6,662
         Net property and equipment . . . . . . . . . .    103,581      96,317    171,524    175,899    210,212
         Total assets . . . . . . . . . . . . . . . . .    111,292     104,286    196,970    204,042    230,041
         Long-term debt, excluding current portion  . .     52,000      54,000     86,311    107,403    122,777
         Redeemable preferred stock . . . . . . . . . .        ---         ---     16,125        ---        ---
         Total shareholders' equity . . . . . . . . . .     49,158      44,279     56,416     74,321     81,466
</TABLE>

------------------------------------
(1)      In December 1994, the Company acquired all of the outstanding common
         stock of ING.
(2)      Amounts for 1994 and 1995 exclude discontinued operations representing
         the Company's natural gas marketing and transportation segment.
(3)      Amount for 1993 reflects the writedown in carrying value of crude oil
         and natural gas properties ($20,000) and reorganization costs
         ($1,000).
(4)      Per share amounts have been computed by dividing net earnings after
         preferred dividends by the weighted average number of shares
         outstanding:  11,847 in 1992; 12,013 in 1993; 14,190 in 1994; 17,932
         in 1995, and 20,457 in 1996, respectively.
(5)      Amount for 1995 includes $17,421 related to net assets of discontinued
         operations.





                                       21
<PAGE>   22
ITEM 7.          MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
                 AND RESULTS OF OPERATIONS

         The following discussion should be read in conjunction with the
Company's consolidated financial statements and notes thereto included
elsewhere herein.

GENERAL

         The Company's business strategy is as follows:

         o       Acquire underdeveloped oil and gas properties, primarily in
                 the interior salt basin of Mississippi, which have geological
                 complexity and multiple producing horizons.  Management
                 believes that the Company's extensive experience in the
                 interior salt basin of Mississippi developed over the past ten
                 years enables it to efficiently increase reserves and improve
                 production rates in this complex geologic environment.
                 Additionally, management believes that such experience gives
                 the Company a significant competitive advantage in evaluating
                 similarly situated acquisition prospects;

         o       Maximize production and continue to increase reserves through
                 relatively low risk activities such as development/delineation
                 drilling; including high-angle and horizontal drilling,
                 multi-zone completions, recompletions, enhancement of
                 production facilities and secondary recovery projects;

         o       Utilize 3-D seismic technology to identify exploration
                 prospects and develop reserves in the vicinity of its existing
                 fields.  The Company began using 3-D seismic technology in the
                 Laurel field in Mississippi in 1983 and has shot two large 3-D
                 seismic programs in and around its existing properties in 1995
                 and 1996;

         o       Achieve a low cost structure through asset concentration in
                 the interior salt basin of Mississippi .  Asset concentration
                 permits operating economies of scale and leverages operational
                 and technical capabilities.  Moreover, Coho continuously
                 reviews its producing properties for operating efficiencies.
                 A typical Coho operated Mississippi salt basin well is highly
                 productive, further reducing operating costs on a per well and
                 per BOE basis;

         o       Control the magnitude, quality and timing of capital
                 expenditures by obtaining high working interests in and
                 operating its properties.  At December 31, 1996 the Company
                 owned an average working interest of 87% and operated over 90%
                 of its producing properties.


LIQUIDITY AND CAPITAL RESOURCES

         Capital Sources.  For the year ended December 31, 1996, cash flow
generated from operating activities was $16.8 million compared with $12.8
million for the same period in 1995. A 13% increase in crude oil production
volumes for the year ended December 31, 1996, compared to the same period in
1995 and price increases of 21% for crude oil and 30% for natural gas are the
major factors contributing to this increase.  See results of operations for a
discussion of operating results.





                                       22
<PAGE>   23
         At December 31, 1996, the Company had working capital of $6.7 million
primarily due to higher than normal oil and gas receivables as a result of new
wells coming online and due to investments in marketable securities.

         On April 3, 1996, the Company's wholly owned subsidiary, ING, sold to
Republic Gas Partners, L.L.C.  ("Republic") all of the stock of its
wholly-owned subsidiaries, Mid Louisiana Gas Company, Mid Louisiana Marketing
Company and Mid Louisiana Gas Transmission Company, which comprised the
Company's Louisiana natural gas marketing and transportation segment of
operations, for total consideration of approximately $23 million.  The total
consideration is comprised of $19.5 million in cash, the assumption of net
liabilities of approximately $2.3 million (excluding deferred taxes) and the
reimbursement for the payment of certain taxes of $1.2 million, generated as a
result of the tax treatment of the transaction.  Republic is an  unrelated
third party.  The proceeds from the sale were used to reduce amounts
outstanding under the Company's revolving credit facility.

         Effective August 8, 1996 the Company amended its revolving credit
facility with its lenders.  Under this new amended credit facility (the
"Restated Credit Agreement"), the lenders have increased their maximum
commitment from $147.5 million to $250 million.  Additionally, the amount
available to the Company in borrowing capacity for general corporate purposes
("Borrowing Base") increased from $110 million to $130 million (further
increased to $150 million on December 31, 1996), with an additional $20 million
immediately available to the Company to provide bridge financing for
acquisitions.  Other changes to the credit facility include: (a) lengthening
the time period for permitted advances and repayments to January 1, 2000 from
January 31, 1998, at which time the loan converts to a non-revolver term
facility requiring quarterly principal repayments until fully repaid in 2003
(previously 2002), and (b) reducing the margin premium charged in excess of
LIBOR for revolving Eurodollar advances, which will now be based on a rolling
four-quarter basis of consolidated indebtedness to earnings before interest,
taxes, depreciation and amortization, currently 1.375%, with the highest
applicable margin being 1.50% (previously 2%).  The repayment of all advances
is guaranteed by Coho Energy, Inc. and outstanding advances are secured by
substantially all of the assets of the Company.

         Outstanding advances under the Company's revolving credit facility at
December 31, 1996 were $120.5 million, all of which is classified as long term.
The Company also had letters of credit aggregating $2.3 million outstanding
under the Company's revolving credit facility as of December 31, 1996, to
secure promissory notes issued in August 1995, relating to the acquisition of
the Brookhaven field in Mississippi, leaving $27.2 million available under the
amended credit facility  at December 31, 1996.

         The Restated Credit Agreement contains certain financial and other
covenants including (i) the maintenance of minimum amounts of shareholders'
equity ($65 million plus 50% of consolidated net income beginning in 1994),
(ii) maintenance of minimum ratios of cash flow to interest expense (2.5 to 1)
as well as current assets (including unused borrowing base) to current
liabilities (1 to 1), (iii) limitations on the Company's ability to incur
additional debt and (iv) restrictions on the payment of dividends.  At December
31, 1996, shareholders' equity exceeded the  minimum required under the
Restated Credit Agreement by approximately $12.6 million and ratios of cash
flow to interest expense and current assets to current liabilities were 4.3 to
1 and 4.08 to 1, respectively.

         Dividends.  While the Company is restricted on the payment of
dividends under the Restated Credit Agreement, dividends are permitted on
Company equity securities provided (i) the Company is





                                       23
<PAGE>   24
not in default under the Restated Credit Agreement; and (ii) (a) the aggregate
sum of the proposed dividend, plus all other dividends or distributions made
since February 8, 1994 do not exceed 50% of cumulative consolidated net income
during the period from January 1, 1992 to the date of the proposed dividend; or
(b) the ratio of total consolidated indebtedness (excluding accounts payable
and accrued liabilities) to shareholders equity does not exceed 1.6 to 1 after
giving effect to such proposed dividend or (c) the aggregate amount of the
proposed dividend, plus all other dividends or distributions made since
February 8, 1994, do not exceed 100% of cumulative consolidated net income for
the three fiscal years immediately preceding the date of payment of the
proposed dividend.  Although the Company has never paid a dividend on its
Common Stock and has no plan to do so in the foreseeable future, the Company
does not believe that the Restated Credit Agreement imposes an undue burden on
the Company's ability to pay dividends.

         Capital Expenditures. During 1996, the Company incurred capital
expenditures of $53.3 million compared with $29.0 million for 1995.  Drilling
activity increased significantly during 1996 over prior years.  The Company
drilled a total of 33 gross wells during 1996 as compared to 7 and 9 gross
wells drilled in 1994 and 1995, respectively.  The majority of the 1996
drilling activity was performed in the Martinville and Brookhaven fields with
the drilling of 12 and 6 gross wells in each respective field.  The remaining
15 wells were drilled in the Monroe field (6 gross wells), the Laurel field (5
gross wells), the Summerland field (3 gross wells) and the Soso field (1 gross
well).  Additionally, 1996 capital expenditures include costs associated with a
37 square mile 3-D seismic program in the Laurel field.  Approximately 38% of
the capital spent in 1996 is associated with projects, primarily waterflood and
3-D seismic projects, which are not yet complete and therefore have not yet had
an effect on daily production.  General and administrative costs directly
associated with the Company's exploration and development activities were $2.5
million for 1996 compared with $1.8 million for 1995 and are included in total
capital expenditures.

         The Company has budgeted capital expenditures of approximately $44
million for 1997, including costs to drill approximately 29 development wells
and 7 exploratory wells.  Management believes that available borrowing under
the Restated Credit Agreement and cash flow from operations will be adequate to
fund anticipated capital expenditures and working capital needs in 1997.  The
Company has no long term capital commitments and, consequently, the Company can
readily adjust its capital expenditure level as circumstances change.

         Hedging.  Oil and gas prices are subject to significant seasonal,
political and other variables which are beyond the Company's control.  In an
effort to reduce the effect on the Company of the volatility of the prices
received for oil and gas, the Company has entered, and expects to continue to
enter, into oil and gas hedging transactions.  The Company's hedging program is
intended to stabilize cash flow and thus allow the Company to plan its capital
expenditures program with greater certainty.  Because all hedging transactions
are tied directly to the Company's oil and gas production and natural gas
marketing operations, the Company does not believe that such transactions are
of a speculative nature.





                                       24
<PAGE>   25

RESULTS OF OPERATIONS

   Selected Operating Data
<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31             
                                                               -----------------------------------------------
                                                                     1994             1995              1996
                                                                     ----             ----              ----
<S>                                                              <C>               <C>                <C>
PRODUCTION:
   Crude Oil (Bbl/day)  . . . . . . . . . . . . . . . . .            5,416             5,966             6,742
   Natural Gas (Mcf/day)  . . . . . . . . . . . . . . . .            1,836            19,431            18,160
   BOE (Bbl/day)  . . . . . . . . . . . . . . . . . . . .            5,722             9,205             9,769

AVERAGE SALES PRICES:
   Crude Oil (per Bbl)  . . . . . . . . . . . . . . . . .        $   12.86          $  13.62          $  16.42
   Natural Gas (per Mcf) (1)  . . . . . . . . . . . . . .        $    1.55          $   1.59          $   2.07

OTHER:
   Production costs per BOE (2)   . . . . . . . . . . . .        $    4.49          $   3.71          $   3.88
   Depletion per BOE  . . . . . . . . . . . . . . . . . .        $    4.78          $   4.38          $   4.55

REVENUES (IN THOUSANDS):
   Production revenues
       Crude Oil  . . . . . . . . . . . . . . . . . . . .        $  25,427          $ 29,654          $ 40,527
       Natural Gas  . . . . . . . . . . . . . . . . . . .            1,037            11,249            13,745 
                                                                 ---------          --------          --------
                                                                 $  26,464          $ 40,903          $ 54,272
                                                                 =========          ========          ========
</TABLE>

(1)      Natural gas prices are net of fuel costs used in gas gathering.
(2)      Includes lease operating expenses and production taxes, exclusive of
         general and administrative costs.


YEAR ENDED DECEMBER 31, 1996 COMPARED WITH YEAR ENDED DECEMBER 31, 1995

         Operating Revenues.  During 1996, production revenues increased 33% to
$54.3 million as compared to $40.9 million in 1995 (including hedging gains and
losses discussed below).  This increase was principally due to increases of 13%
in crude oil production, 21% in crude oil prices and 30% in natural gas prices
which were slightly offset by a 6% decrease in natural gas production.

         The 13% increase in daily crude oil production for 1996 to 6,742 Bbls
is primarily a result of continued development activity, including
recompletions and workovers on existing wells and drilling new wells and
waterflood operations in the Martinville, Soso and Summerland fields and
waterflooding and exploration success in Martinville.  In addition, 1996
includes oil production from the Brookhaven field for the entire year as
compared to only five months in 1995.  Gas production for 1996 was 6% lower
than 1995, primarily due to operational problems associated with the gas
gathering system caused by unusually cold, wet weather during the  winter
months of 1996.  Although the Monroe gas field (the Company's primary gas
field) is experiencing normal production declines, production from new
development wells in the field should offset such declines absent the
operational problems discussed above.





                                       25
<PAGE>   26
         In 1996, the posted price for the Company's crude oil averaged $20.23
per Bbl, a 21% increase over the average posted price of $16.73 experienced in
1995.  The price per barrel received by the Company is adjusted for the quality
of the crude oil and is generally lower than the posted price.  The crude oil
prices received by the Company during 1996 increased more significantly than
the average posted price because the Company amended its marketing arrangements
for the sale of substantially all of its crude oil during 1995  and again in
March 1996, to improve the price and resultant revenues it receives for its
crude oil.

         The price for the Company's natural gas, including hedging gains and
losses, increased 30% in  1996 compared to 1995 due to increased demands for
natural gas.

         Production revenues for 1996 included crude oil hedging losses of $4.7
million ($1.92 per Bbl) compared to hedging losses of $.6 million ($.27 per
Bbl) in 1995.  Production revenues in 1996 also included natural gas hedging
losses of $1.2 million ($.18 per Mcf) compared with natural gas hedging gains
of $1.0 million ($.15 per Mcf) in 1995.  The Company has entered into certain
arrangements which fix a minimum West Texas Intermediate ("WTI") price per
barrel of $18.00 and a maximum WTI price of $21.30 for 4,000 barrels of oil
production per day for the period January 1, 1997 through June 30, 1997 and
arrangements which fix an average WTI price of $23.47 for 3,000 barrels of oil
production per day for the period January 1, 1997 through March 31, 1997.  The
Company also has 15,000 Mmbtu per day of natural gas production hedged for the
months January through March 1997, at an average price of $3.07 per Mmbtu.  Any
gain or loss on the Company's crude oil hedging transactions is determined as
the difference between the contract price and the average closing price for WTI
on the NYMEX for the contract period.  Any gain or loss on the Company's
natural gas hedging transactions is generally determined as the difference
between the contract price and the average settlement price for the last three
days during the month in which the hedge is in place.  Consequently, hedging
activities do not affect the actual sales price received for the Company's
crude oil and natural gas.

         Interest and other income increased to $1.0 million in 1996 from
$92,000 in 1995 due to $472,000 of interest earned during 1996 on the
receivable from the sale of the marketing and pipeline segment of operations
and due to an unrealized gain of $450,000 on marketable securities.

         Expenses.  Production expenses were $13.9 million in 1996 compared to
$12.5 million for 1995.  This increase primarily reflects additional production
volumes.  On a BOE basis, production costs increased to $3.88 per BOE in 1996
compared to $3.71 per BOE in 1995, primarily due to an increase of $.15 per BOE
in production taxes as a result of higher oil and gas prices.

         General and administrative expenses increased 35% in 1996 to $7.3
million, primarily due to increased compensation and employee related costs
attributable to staff additions made during the last half of 1995 and during
1996 to handle the increased drilling and recompletion activity.  Additionally,
1996 expenses include an estimated bonus accrual of approximately $812,000
associated with the 1996 bonus plan, discussed in the Company's 1995 Proxy
Statement, which is awarded based on the Company's after tax return on equity
for the year.  As a result of these increases, general and administrative
expenses per BOE increased 26% from $1.61 in 1995 to $2.03 in 1996.

                 Depletion and depreciation expense increased 11% to $16.3
million in 1996.  This increase is primarily the result of increased production
volumes.  The depletion rate per BOE in 1996 increased 4% to $4.55 versus $4.38
for 1995.





                                       26
<PAGE>   27
         Interest expense increased 5% to $8.5 million in 1996 from $8.1
million in 1995 due to higher borrowing levels, which were partially offset by
a decrease in interest rates.  Borrowing levels increased by $2.0 million to
$105.4 million prior to the paydown of $20.5 million on April 3, 1996 from the
proceeds of the pipeline sale discussed under "Liquidity and Capital Resources
- Capital Sources".  Since April, borrowing levels have increased by $35.6
million to $120.5 million to fund increased drilling activities.  The average
interest rate paid on outstanding indebtedness under the Company's revolving
credit facility was 7.6% in 1996, compared to 8.4% in 1995.

         The Company's net operating loss carryforwards ("NOLs") for United
States and Canadian federal income tax purposes were approximately  $71 million
at December 31, 1996 and expire between 1997 and 2010.  Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109")
requires that the tax benefit of such NOLs be recorded as an asset to the
extent that management assesses the utilization of such NOLs to be "more likely
than not".  It is expected that future reversals of existing taxable temporary
differences will generate taxable amounts sufficient to utilize the majority of
the NOL carryforwards prior to their expiration. A valuation allowance has been
established with respect to approximately $9 million of these NOLs as it is
uncertain whether they will be utilized before they expire.

         The Company's net earnings for the year ended December 31, 1996 were
$5.9 million, as compared to $1.8 million in 1995 (including $1.6 million of
income from discontinued operations) for the reasons discussed above.

YEAR ENDED DECEMBER 31, 1995 COMPARED WITH YEAR ENDED DECEMBER 31, 1994

         Operating Revenues. During 1995, production revenues increased 55% to
$40.9 million as compared to $26.5 million in 1994.  This increase was
principally due to increased natural gas production, a 10% increase in crude
oil production and a 6% increase in crude oil prices received.

         The 10% increase in daily crude oil production for 1995 to 5,966 Bbls
was primarily a result of the continued positive response from the Company's
waterflood projects in the Laurel field, particularly in the Rodessa formation,
as well as results from increased drilling at Summerland, where four wells were
drilled in the last half of 1994 and first half of 1995.  The significant
increase in natural gas production, to approximately 19.4 Mmcf per day,
reflected the Company's acquisition of ING in December 1994 and ING's
production from the Monroe field in north Louisiana.  While Coho had very
little natural gas production prior to the acquisition, the Company's
production profile during 1995 was 65% oil and 35% natural gas.

         Crude oil prices increased significantly during the first half of 1995
compared to the same period in 1994 and were reasonably stable for the balance
of 1995.  The posted price for the Company's crude oil averaged $16.73 per Bbl
for 1995, an  8% increase over the average posted price of $15.55 per Bbl
experienced in 1994.  The price per barrel received by the Company is adjusted
for the quality and gravity of crude oil and is generally lower than the posted
price.  The crude oil prices received by the Company during 1995 did not
increase as significantly as the average posted price because the price
recorded by the Company includes the effects of the hedging gains and losses
discussed below.  During 1995, the Company amended certain of its marketing
arrangements for the sale of substantially all of its crude oil.  The new sales
agreement reduced the spread between the posted price and the price received





                                       27
<PAGE>   28
by the Company by approximately $.75 per Bbl, resulting in a net increase in
revenues to the Company.  This change was effective during the second quarter
of 1995.

         The price for natural gas deteriorated during the first nine months of
1995 from 1994 year end prices.  Mild winter weather across the United States
and delayed summer temperature increases reduced demand during the normally
higher volume heating and cooling seasons, and prices reflected this reduced
demand.  During the fourth quarter of 1995, demand increased and gas prices
responded.  In 1995, the average price per Mcf of gas received by the Company
was $1.59.

         Production revenues for 1995 included crude oil hedging losses of
$593,000 ($.27 per Bbl), while production revenues for 1994 included hedging
gains of $1.1 million ($0.54 per Bbl).  Production revenues in 1995 also
include natural gas hedging gains of $1.0 million  ($.15 per Mcf).

         Expenses.  Production expenses (including production taxes) were $12.5
million in 1995 compared to $9.4 million in 1994.  This increase reflects
additional production volumes.  On a BOE basis, production costs decreased to
$3.71 per BOE in 1995 compared to $4.49 per BOE in 1994.  This decrease was the
result of increased natural gas production in 1995, which typically has lower
operating costs than oil wells, and increased oil production volumes, which
also tend to reduce costs on a BOE basis.

         General and administrative costs increased substantially in 1995 to
$5.4 million compared to $3.4 million in 1994.  This increase was a result of
increased staff to administer the production operations acquired in the ING
acquisition.  General and administrative expenses were $1.61 per BOE in 1995
and $1.64 per BOE in 1994.  During 1995, the Company effected 41 of 42 planned
employee terminations and paid termination benefits totalling $2.1 million,
which were offset against a restructuring charge which was accrued in 1994.

         Interest expense increased to $8.1 million in 1995 from $4.2 million
in 1994.  This increase was primarily due to higher borrowing levels related to
the acquisition of ING in December 1994, as well as the Company's ongoing
capital expenditure program.  Advances under the Company's revolving credit
facility were $103.4 million (excluding gas storage loans) at December 31,
1995, compared to $86 million at December 31, 1994.  The general increase in
interest rates also contributed to the increase in interest costs for the
period.  The average interest rate paid on outstanding indebtedness under the
Company's revolving credit facility was 8.4% in 1995, compared to 6.8% in 1994.

         Depletion and depreciation expense increased 47% to $14.7 million in
1995 from $10.0 million in 1994, as a result of the ING acquisition and the
resultant increased gas production volumes combined with the increased oil
production volumes in 1995.  The depletion rate per BOE decreased to $4.38 in
1995 as compared to $4.78 in 1994.  The per BOE decrease results from lower
depletion rates on the ING reserves and from additions in proved oil reserves
associated with the Company's exploration and development activities.

         The Company's net income for 1995 was $1.8 million, including $1.6
million of income from discontinued marketing and transportation operations, as
compared to a net loss of $1.6 million in 1994 for the reasons discussed above.





                                       28
<PAGE>   29

ITEM 8.  FINANCIAL STATEMENTS

                        INDEX OF FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
                                                                                                                     Page
                                                                                                                     ----
<S>                                                                                                                 <C>
Independent Auditors' Reports   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30-31

Consolidated Balance Sheets, December 31, 1995 and 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  32

Consolidated Statements of Earnings, Years Ended December 31, 1994, 1995 and 1996   . . . . . . . . . . . . . . . . .  33

Consolidated Statements of Shareholders' Equity, Years Ended December 31, 1994, 1995 and 1996   . . . . . . . . . . .  34

Consolidated Statements of Cash Flows, Years Ended December 31, 1994, 1995 and 1996   . . . . . . . . . . . . . . . .  35

Notes to Consolidated Financial Statements  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36-55
</TABLE>





                                       29
<PAGE>   30
                    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. (a Texas corporation) and subsidiaries for the years ended
December 31, 1996 and 1995, and the related consolidated statements of
earnings, shareholders' equity, and cash flows for the years then ended.  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 audit in accordance with generally accepted auditing
standards. 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 for the years ended December 31, 1996 and 1995, and the
results of their operations and their cash flows for the years then ended in
conformity with generally accepted accounting principles.

         We have also audited the adjustments described in Note 2 that were
applied to restate the 1994 financial statements.  In our opinion, such
adjustments are appropriate and have been properly applied.

                                        Arthur Andersen, LLP


Dallas, Texas
February 21, 1997





                                       30
<PAGE>   31
                          INDEPENDENT AUDITORS' REPORT

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

         We have audited the accompanying  consolidated statement of earnings,
shareholders' equity, and cash flows of Coho Energy, Inc. and subsidiaries for
the year ended December 31, 1994.  These consolidated financial statements are
the responsibility of the Company's management.  Our responsibility is to
express an opinion on these consolidated financial statements based on our
audit.

         We conducted our audit in accordance with generally accepted auditing
standards. 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 audit provides a reasonable basis
for our opinion.

         In our opinion, the consolidated financial statements of Coho Energy,
Inc. and subsidiaries  referred to above present fairly, in all material
respects,  the results of their operations and their cash flows for the year
ended December 31, 1994, in conformity with generally accepted accounting
principles.


                                        KPMG Peat Marwick LLP

Dallas, Texas
February 24, 1995





                                       31
<PAGE>   32
                                   COHO ENERGY, INC.
                                    and Subsidiaries
                               CONSOLIDATED BALANCE SHEETS
                   (in thousands, except share and per share amounts)
<TABLE>
<CAPTION>
                                                                                    DECEMBER 31        
                                                                             ------------------------
                                  ASSETS
                                                                                   1995         1996
                                                                                   ----         ----
<S>                                                                          <C>            <C>
CURRENT ASSETS
    Cash and cash equivalents   . . . . . . . . . . . . . . . . . . . . .    $    1,430      $  1,864
    Accounts receivable, principally trade  . . . . . . . . . . . . . . .         5,049        11,884
    Deferred income taxes   . . . . . . . . . . . . . . . . . . . . . . .           973           913
    Investment in marketable securities   . . . . . . . . . . . . . . . .           ---         1,962
    Other current assets  . . . . . . . . . . . . . . . . . . . . . . . .           869           995
    Net assets of discontinued operations (note 2)  . . . . . . . . . . .        17,421           ---
                                                                             ----------     ---------
                                                                                 25,742        17,618
PROPERTY AND EQUIPMENT, at cost net of accumulated depletion and
   depreciation, based on full cost accounting method, (note 3)  . . . . .      175,899       210,212

OTHER ASSETS  . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .        2, 401        2, 211
                                                                             ----------     ---------
                                                                             $  204,042     $ 230,041
                                                                             ==========     =========
                          LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
    Accounts payable, principally trade   . . . . . . . . . . . . . . . .    $    4,108     $   5,752
    Accrued liabilities and other payables  . . . . . . . . . . . . . . .         6,933         5,043
    Current portion of long term debt (note 4)  . . . . . . . . . . . . .           268           161
                                                                             ----------     ---------
                                                                                 11,309        10,956
LONG TERM DEBT, excluding current portion (note 4)  . . . . . . . . . . .       107,403       122,777

DEFERRED INCOME TAXES (note 5)  . . . . . . . . . . . . . . . . . . . . .        11,009        14,842
                                                                             ----------     ---------
                                                                                129,721       148,575
                                                                             ----------     ---------
COMMITMENTS AND CONTINGENCIES (note 9)

SHAREHOLDERS' EQUITY (note 8)
    Preferred stock, par value $0.01 per share
       Authorized 10,000,000 shares, none issued
    Common stock, par value $0.01 per share
       Authorized 50,000,000 shares
       Issued 20,165,263 and 20,347,126 shares at December 31, 1995 and
       1996, respectively   . . . . . . . . . . . . . . . . . . . . . . .           202           203
    Additional paid-in capital  . . . . . . . . . . . . . . . . . . . . .        82,278        83,516
    Retained deficit  . . . . . . . . . . . . . . . . . . . . . . . . . .        (8,159)       (2,253)
                                                                             ----------     ----------
    Total shareholders' equity  . . . . . . . . . . . . . . . . . . . . .        74,321        81,466
                                                                             ----------     ---------
                                                                             $  204,042     $ 230,041
                                                                             ==========     =========
</TABLE>

          SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





                                       32
<PAGE>   33
                               COHO ENERGY, INC.
                                and Subsidiaries
                      CONSOLIDATED STATEMENTS OF EARNINGS
                    (in thousands, except per share amounts)

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31     
                                                                        --------------------------------
                                                                          1994         1995       1996
                                                                          ----         ----       ----
<S>                                                                      <C>                    <C>
OPERATING REVENUES
    Crude oil and natural gas production (note 10)  . . . . . . . . .    $ 26,464  $   40,903   $ 54,272
                                                                         --------- -----------  --------
OPERATING EXPENSES
    Crude oil and natural gas production  . . . . . . . . . . . . . .       7,840      10,514     11,277
    Taxes on oil and gas production   . . . . . . . . . . . . . . . .       1,532       1,943      2,598
    General and administrative  . . . . . . . . . . . . . . . . . . .       3,435       5,400      7,264
    Restructuring expenses (note 12)  . . . . . . . . . . . . . . . .         973         ---        ---
    Depletion and depreciation  . . . . . . . . . . . . . . . . . . .       9,989      14,717     16,280
                                                                         --------- -----------  --------
         Total operating expenses . . . . . . . . . . . . . . . . . .      23,769      32,574     37,419
                                                                         --------- -----------  --------
OPERATING INCOME (LOSS) . . . . . . . . . . . . . . . . . . . . . . .       2,695       8,329     16,853
                                                                         --------- -----------  --------
OTHER INCOME AND EXPENSES
    Interest and other income   . . . . . . . . . . . . . . . . . . .         218          92      1,012
    Interest expense  . . . . . . . . . . . . . . . . . . . . . . . .      (4,190)     (8,140)    (8,476)
                                                                         --------- -----------  ---------
                                                                           (3,972)     (8,048)    (7,464)
                                                                         --------- -----------  ---------
EARNINGS (LOSS) FROM CONTINUING
 OPERATIONS BEFORE INCOME TAXES . . . . . . . . . . . . . . . . . . .      (1,277)        281      9,389
                                                                         --------- -----------  --------
INCOME TAXES (note 5)
    Current (recovery) expense  . . . . . . . . . . . . . . . . . . .         (11)        457       (411)
    Deferred (reduction) expense  . . . . . . . . . . . . . . . . . .        (292)       (345)     3,894
                                                                         --------- -----------  --------
                                                                             (303)        112      3,483
                                                                         --------- -----------  --------
NET EARNINGS (LOSS) FROM CONTINUING OPERATIONS  . . . . . . . . . . .        (974)        169      5,906
DISCONTINUED OPERATIONS (note 2)
    Income (Loss) from discontinued marketing and transportation
      operations (less applicable income tax expense (benefit) of
      $(417) and $1,384 in 1994 and 1995, respectively)   . . . . . .        (680)      1,611        ---
                                                                         --------- -----------  --------
NET EARNINGS (LOSS) . . . . . . . . . . . . . . . . . . . . . . . . .      (1,654)      1,780      5,906
DIVIDENDS ON PREFERRED STOCK  . . . . . . . . . . . . . . . . . . . .         (86)       (944)       ---
                                                                         --------- -----------  --------
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                           $ (1,740) $      836   $  5,906
                                                                         ========= ===========  ========
EARNINGS (LOSS) FROM CONTINUING OPERATIONS
  PER  COMMON SHARE . . . . . . . . . . . . . . . . . . . . . . . . .    $  (0.07) $    (.02)   $   .29
                                                                         ========= ===========  =======
EARNINGS (LOSS) PER COMMON SHARE  . . . . . . . . . . . . . . . . . .    $  (0.12) $     .05    $   .29
                                                                         ========= ===========  =======
</TABLE>


          SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





                                       33
<PAGE>   34

                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                    (IN THOUSANDS, EXCEPT NUMBERS OF SHARES)




<TABLE>
<CAPTION>
                                                          NUMBER OF                 ADDITIONAL    RETAINED
                                                        COMMON SHARES    COMMON      PAID-IN      EARNINGS
                                                         OUTSTANDING      STOCK      CAPITAL     (DEFICIT)      TOTAL
                                                         -----------      -----      -------     ---------      -----
<S>                                                       <C>               <C>      <C>        <C>          <C>
Balance at December 31, 1993  . . . . . . . . . . . . .    14,007,302       $140     $ 51,394    $ (7,255)   $  44,279
  Issued on                                                                                     
   (i)  Acquisition of Interstate Natural                                                       
        Gas Company   . . . . . . . . . . . . . . . . .     2,775,000         28       13,847         ---       13,875
   (ii) Exercise of Employee Stock Options  . . . . . .           623        ---            2         ---            2
  Net loss  . . . . . . . . . . . . . . . . . . . . . .           ---        ---          ---      (1,654)      (1,654)
  Dividends on preferred stock  . . . . . . . . . . . .           ---        ---          ---         (86)         (86)
                                                          ----------       -----     --------    --------    ---------
Balance at December 31, 1994  . . . . . . . . . . . . .    16,782,925        168       65,243      (8,995)      56,416
  Issued on                                                                                     
   (i)  Exchange of preferred stock (note 7)  . . . . .     3,225,000         32       16,093         ---       16,125
   (ii)  Satisfaction of accrued preferred                                                      
           dividends (note 7) . . . . . . . . . . . . .       157,338          2          942         ---          944
  Net earnings  . . . . . . . . . . . . . . . . . . . .           ---        ---          ---       1,780        1,780
  Dividends on preferred stock  . . . . . . . . . . . .           ---        ---          ---        (944)        (944)
                                                          -----------      -----     --------    --------    ---------
Balance at December 31, 1995  . . . . . . . . . . . . .    20,165,263        202       82,278      (8,159)      74,321
  Issued on                                                                                     
   (i)  Exercise of Employee Stock Options  . . . . . .        81,863        ---          414         ---          414
   (ii) Acquisition of working interest . . . . . . . .       100,000          1          824         ---          825
  Net earnings  . . . . . . . . . . . . . . . . . . . .            --        ---          ---       5,906        5,906
                                                          -----------       ----     --------    --------     --------
                                                                   --                            
                                                                   --                            
Balance at December 31, 1996  . . . . . . . . . . . . .    20,347,126      $ 203     $ 83,516   $  (2,253)    $ 81,466
                                                          ===========      =====     ========   =========     ========
</TABLE>





          SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





                                       34
<PAGE>   35
                                        COHO ENERGY, INC.
                                         AND SUBSIDIARIES
                              CONSOLIDATED STATEMENTS OF CASH FLOWS
                                          (IN THOUSANDS)
<TABLE>
<CAPTION>
                                                                                  YEAR ENDED DECEMBER 31       
                                                                           ----------------------------------
                                                                           1994          1995         1996
                                                                           ----          ----         ----
<S>                                                                        <C>            <C>         <C>
Cash flows from operating activities
    Net earnings (loss)   . . . . . . . . . . . . . . . . . . . . . .      $ (1,654)      $ 1,780     $  5,906
    Adjustments to reconcile net earnings (loss)
      to net cash provided (used) by operating activities:
         Depletion and depreciation . . . . . . . . . . . . . . . . .        10,074        15,876       16,280
         Deferred income taxes  . . . . . . . . . . . . . . . . . . .          (709)          653        3,894
         Amortization of debt issue costs and other . . . . . . . . .           217           918          271
    Changes in:
         Accounts receivable  . . . . . . . . . . . . . . . . . . . .        (1,233)       (4,696)      (6,983)
         Inventory  . . . . . . . . . . . . . . . . . . . . . . . . .         1,803         2,060          ---
         Accounts payable and accrued liabilities . . . . . . . . . .        (6,260)       (3,221)          40
         Other assets . . . . . . . . . . . . . . . . . . . . . . . .        (1,524)         (872)        (489)
         Investment in marketable securities  . . . . . . . . . . . .           ---           ---       (1,512)
         Deferred income taxes and other current liabilities  . . . .           287           337         (560)
         Deferred hedging gain  . . . . . . . . . . . . . . . . . . .        (1,683)          ---          ---
                                                                           --------       -------     --------
Net cash provided (used) by operating activities  . . . . . . . . . .          (682)       12,835       16,847
                                                                           --------       -------     --------
Cash flows from investing activities
    Property and equipment  . . . . . . . . . . . . . . . . . . . . .       (19,503)      (29,970)     (52,384)
    Changes in accounts payable and accrued liabilities related to
    exploration                                                                 428           986         (902)
      and development   . . . . . . . . . . . . . . . . . . . . . . .
    Cash included in net assets of discontinued operations  . . . . .           ---          (352)         ---
    Proceeds on sale of property and equipment  . . . . . . . . . . .           ---           ---       21,476
    Net non cash assets of acquired company (note 6)  . . . . . . . .       (12,549)          ---          ---
                                                                           --------       -------     --------
Net cash used in investing activities . . . . . . . . . . . . . . . .       (31,624)      (29,336)     (31,810)
                                                                           --------       -------     ---------
Cash flows from financing activities                                                             
    Increase in long term debt  . . . . . . . . . . . . . . . . . . .        37,567        19,140       52,600
    Repayment of long term debt   . . . . . . . . . . . . . . . . . .        (7,500)       (1,822)     (37,617)
    Increase in gas storage loan  . . . . . . . . . . . . . . . . . .           ---         4,000          ---
    Repayment of gas storage loan   . . . . . . . . . . . . . . . . .           ---        (5,000)         ---
    Proceeds from exercised stock options   . . . . . . . . . . . . .           ---           ---          414
    Issuance of common stock  . . . . . . . . . . . . . . . . . . . .             2           ---          ---
    Dividends on preferred stock  . . . . . . . . . . . . . . . . . .           (86)          ---          ---
                                                                           --------       -------     --------
Net cash provided by financing activities . . . . . . . . . . . . . .        29,983        16,318       15,397
                                                                           --------       -------     --------
Net increase (decrease) in cash and cash equivalents  . . . . . . . .        (2,323)         (183)         434
Cash and cash equivalents at beginning of year  . . . . . . . . . . .         3,936         1,613        1,430
                                                                           --------       -------     --------
Cash and cash equivalents at end of year  . . . . . . . . . . . . . .      $  1,613       $ 1,430     $  1,864
                                                                           ========       =======     ========
</TABLE>



          SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





                                       35
<PAGE>   36
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
        (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").  Prior to September 29, 1993, CRI was a publicly held company of
which Coho Resources Limited, a publicly held Alberta, Canada Company ("CRL"),
held a 68% ownership interest.  As a result of a reorganization effective on
September 29, 1993 (the "1993 Reorganization"), CRI and CRL became wholly-owned
subsidiaries of CEI.

    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.

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

    Cash Equivalents

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

    Marketable Securities

         In accordance with Statement of Financial Accounting Standards No.
115, "Accounting for Certain Instruments in Debt and Equity Securities", the
Company has classified all equity securities as trading securities and adjusted
such securities to market value at the end of each period.  Unrealized gains
and losses on trading securities are reported in earnings.  Trading
securities, as of December 31, 1996, had a fair value of $1,962,000 and gross
unrealized gains of $722,000.

    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.  All internal
corporate costs relating to crude oil and natural gas producing activities are
expensed as incurred.  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.





                                       36
<PAGE>   37
         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.

    Estimates

         The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period.  Actual results could differ from those estimates.

    Impairment of Long-Lived Assets

         During fiscal year 1996, the Company adopted SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived-Assets To Be
Disposed Of."  The Company has no assets which meet the test for impairment.

    Other Assets

         Other assets generally include deferred financing charges which are
amortized over the term of the related financing under the effective interest
rate method.

    Stock-Based Compensation

         Statement of Financial Accounting Standards 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 the date of the grant over the amount an employee must
pay to acquire the stock.

    Earnings Per Common Share

         Earnings per common share are based upon the weighted average number
of common shares outstanding (including common shares plus, when their effect
is dilutive, common stock equivalents consisting of stock options) for the
years ended (1994 - 14,190,029; 1995 - 17,931,993; 1996 - 20,457,398) after
consideration of preferred dividends.

    Income Taxes

         The Company accounts for income taxes in accordance with FASB
Statement of Financial Accounting Standards No.  109, "Accounting for Income
Taxes".  Under the asset and liability method of Statement 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 bases. Deferred





                                       37
<PAGE>   38
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

         Periodically, the Company enters into futures contracts which are
traded on the stock exchanges in order to fix the price on a portion of its
crude oil and natural gas production. Changes in the market value of crude oil
and natural gas futures contracts are reported as an adjustment to revenues in
the period in which the hedged production or inventory is sold. The gain or
loss on the Company's hedging transactions is determined as the difference
between the contract price and a reference price, generally closing prices on
the New York Mercantile Exchange.

    Revenue Recognition Policy

         Revenues generally are recorded when products have been delivered and
services have been performed.  Natural gas transportation revenues are
recognized based upon contractual terms and the related transported volume.


2.  DISCONTINUED OPERATIONS

         On April 3, 1996, the Company's wholly owned subsidiary, Interstate
Natural Gas Company ("ING"), sold the stock of three wholly-owned subsidiaries
that comprised its natural gas marketing and transportation segment to an
unrelated third party for cash of $19.5 million, the assumption of net
liabilities of approximately $2.3 million and the payment of taxes of $1.2
million generated as a result of the tax treatment of the transaction.  The
marketing and transportation segment is accounted for as discontinued
operations, and accordingly, its operations are segregated in the accompanying
statements of operations.

         Revenues of the marketing and transportation segment were $7,965,000
and $71,773,000 for 1994 and 1995, respectively.  Certain expenses have been
allocated to discontinued operations, including interest expense, which was
allocated on the ratio of net assets discontinued to the total net assets
acquired from ING  applied to the $20 million of cash borrowed to acquire ING.

         The components of net assets of discontinued operations included in
the Consolidated Balance Sheet as of December 31, 1995, were as follows:

<TABLE>
<S>                                                       <C>
Cash  . . . . . . . . . . . . . . . . . . . . . . .       $   352
Accounts receivable . . . . . . . . . . . . . . . .        11,606
Inventory . . . . . . . . . . . . . . . . . . . . .         2,555
Other current assets  . . . . . . . . . . . . . . .         1,682
Property, plant and equipment, net  . . . . . . . .        21,054
Accounts payable  . . . . . . . . . . . . . . . . .        (6,400)
Accrued liabilities . . . . . . . . . . . . . . . .        (2,821)
Gas storage loan  . . . . . . . . . . . . . . . . .        (4,000)
Other liabilities . . . . . . . . . . . . . . . . .        (5,318)
Deferred income taxes . . . . . . . . . . . . . . .        (1,289)
                                                          -------
                                                          $17,421
                                                          =======
</TABLE>





                                       38
<PAGE>   39
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

3.  PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>
                                                                                  DECEMBER 31     
                                                                           ------------------------
                                                                              1995          1996
                                                                              ----          ----
<S>                                                                         <C>           <C>
    Crude oil and natural gas leases and rights  including
         exploration, development and equipment thereon, at cost             $278,197     $328,836
    
    Accumulated depletion and depreciation  . . . . . . . . . . . . .        (102,298)    (118,624)
                                                                            ---------    ---------
                                                                            $ 175,899     $210,212
                                                                            =========     ========
</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 totalled
$1,371,000, $1,788,000 and $2,452,000 in 1994, 1995 and 1996, respectively.

    During 1994, 1995 and 1996, 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 totalling $6,254,000 and
$8,284,000 at December 31, 1995 and 1996, respectively, have been excluded from
costs subject to depletion.  These costs are anticipated to be included in
costs subject to depletion during the next three to five years.

    Depletion and depreciation expense per equivalent barrel of production was
$4.78, $4.38 and $4.55 in 1994, 1995 and 1996, respectively.

4.  LONG TERM DEBT
<TABLE>
<CAPTION>
                                                                     1995          1996
                                                                     ----          ----
         <S>                                                       <C>           <C>
         Revolving credit facility  . . . . . . . . . . . .        $103,400      $120,500
         Promissory notes   . . . . . . . . . . . . . . . .           4,190         2,323
         Other  . . . . . . . . . . . . . . . . . . . . . .             485           234
                                                                   --------      --------
                                                                    108,075       123,057
         Less:                                                                   
             Unamortized discount on promissory notes . . .            (404)         (119)
             Current maturities on long term debt . . . . .            (268)         (161)
                                                                   --------      --------
                                                                   $107,403      $122,777
                                                                   ========      ========
</TABLE>
    Revolving Credit Facility

         In August 1992, the Company established a revolving credit and term
loan facility with a group of international and domestic financial
institutions.  The agreement, as amended and restated ("the Restated Credit





                                       39
<PAGE>   40
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


Agreement"), provides a maximum facility of $250 million for general corporate
purposes.  The amount actually available to the Company ("Borrowing Base") is
determined on the basis of a discounted present value attributable to the
Company's proved crude oil and natural gas properties as determined from time
to time by the Company's lenders.  As of December 31, 1996, the Borrowing Base
was $150 million, with an additional $20 million immediately available to the
Company to provide bridge financing for acquisitions.  The Borrowing Base is
redetermined semi-annually by the group of financial institutions.  Outstanding
advances as of December 31, 1996, were $120.5  million.  The Company also has
letters of credit aggregating $2.3 million outstanding under the revolving
credit facility as of December 31, 1996, to secure the promissory notes,
leaving $27.2 million in available borrowing under the credit facility for
general corporate purposes.  The Restated Credit Agreement permits advances and
repayments until January 1, 2000, at which time the outstanding advances will
convert to a non-revolving term facility.  The repayment of all advances is
guaranteed by Coho Energy, Inc. and outstanding advances are secured by
substantially all of the assets of the Company.

         Loans under the Restated Credit Agreement bear interest, at the option
of the Company, at Prime or a Eurodollar rate plus a maximum of 1.5% (currently
1.375%) and are secured by a lien on substantially all of the Company's crude
oil and natural gas properties and the capital stock of the Company's
wholly-owned subsidiaries.  In January 2000, the loan converts to a
non-revolver term facility requiring quarterly repayments until fully repaid in
2003.  If the outstanding amount of the loan exceeds the Borrowing Base at any
time, the Company is required to either provide collateral with value equal to
such excess or prepay the principal amount of the notes equal to such excess in
five (5) equal monthly installments provided the entire excess shall be paid
prior to the immediately succeeding redetermination date.  The fee on the
portion of the unused credit facility is .375% per annum.  The commitment fee
applicable to increases from time to time in the Borrowing Base is .375% of the
incremental Borrowing Base amount.

         The Restated Credit Agreement contains certain financial and other
covenants including (i) the maintenance of minimum amounts of shareholder's
equity, (ii) maintenance of minimum ratios of cash flow to interest expense as
well as current assets to current liabilities, (iii) limitations on the
Company's and CRI's ability to incur additional debt, and (iv) restrictions on
the payment of dividends.

         Promissory Notes

         In August 1995, the Company entered into noninterest bearing
promissory notes aggregating $4.2 million ($3.8 million net of discount based
on an imputed interest rate of 8.13%) due in two installments of $1.9 million
in August 1996 and $2.3 million in August 1997 in connection with the
Brookhaven Acquisition (note 6).  At December 31, 1996, the $2.3 million due in
August 1997 remains outstanding and is classified as long term debt due to the
Company's intent to borrow funds under the long term credit facility for such
payments.  The remaining promissory notes are fully secured by letters of
credit issued under the Company's revolving credit.

         Debt Repayments

         Assuming the Borrowing Base for the revolving credit facility is not
reduced below the current loan balance outstanding and the maturity dates of
the loans are not extended, estimated aggregate principal repayments for each
of the next five years are as follows: ; 1997 - $161,000; 1998 - $57,000; 1999-
$16,000; 2000 - $35,092,000; 2001 - $35,092,000 and $52,639,000 thereafter.





                                       40
<PAGE>   41
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


5.  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, 1995 and 1996, were as follows:

<TABLE>
<CAPTION>
                                                                            1995        1996
                                                                            ----        ----
         <S>                                                               <C>         <C>
         DEFERRED TAX ASSETS
                            
                 Net operating loss carryforwards . . . . . . . . . .      $28,513     $26,087
                 Alternative minimum tax credit carryforwards . . . .          758       1,866
                 Employee benefits  . . . . . . . . . . . . . . . . .          170          46
                 Other  . . . . . . . . . . . . . . . . . . . . . . .          171         (46)
                                                                           -------     ------- 
                 Total gross deferred tax assets  . . . . . . . . . .       29,612      27,953
                 Less valuation allowance . . . . . . . . . . . . . .       (3,679)     (4,150)
                                                                           -------     ------- 
                 Net deferred tax assets  . . . . . . . . . . . . . .       25,933      23,803
                                                                           -------     -------

         DEFERRED TAX LIABILITIES
                                 
                 Property and equipment, due to differences
                          in depletion and depreciation . . . . . . .       35,969      37,732
                                                                           -------     -------
         NET DEFERRED TAX LIABILITY . . . . . . . . . . . . . . . . .      $10,036     $13,929
                                                                           =======     =======
</TABLE>


         The valuation allowance for deferred tax assets as of December 31,
1995 and 1996 includes $2,035,000 and $2,052,000, 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.





                                       41
<PAGE>   42
                              COHO ENERGY, INC.
                              AND SUBSIDIARIES
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

         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>
                                                                 1994       1995      1996
                                                                 ----       ----      ----
         <S>                                                   <C>         <C>
         Earnings (loss) before income taxes
             from continuing operations . . . . . . . . .      $(1,277)    $  281   $ 9,389
                                                               ========    ======   =======

         Expected income tax expense (recovery)
             (statutory rate - 34%) . . . . . . . . . . .      $  (434)    $   95   $ 3,192
         State taxes - deferred . . . . . . . . . . . . .          (66)       232      (353)
         Federal benefit of state taxes . . . . . . . . .           22        (78)      120
         Change in valuation allowance  . . . . . . . . .          182       (168)      471
         Other  . . . . . . . . . . . . . . . . . . . . .           (7)        31        53
                                                               -------     ------   -------
                                                               $  (303)    $  112   $ 3,483
                                                               =======     ======   =======
</TABLE>

    At December 31, 1996, 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  . . . .        1997                  $  1,723
                                                                                 1998                     5,432
                                                                                 1999                     1,727
                                                                                 2000                     4,253
                                                                                 2001                     3,015
                                                                              2002-2010                  51,049
                                                                                                        -------
                                                                                                        $67,199
                                                                                                        =======
    Operating loss carryforwards for Canadian  income tax purposes  . . .     1999-2003                 $ 4,049
                                                                                                        =======
      Operating loss carryforwards for federal alternative minimum tax
            purposes  . . . . . . . . . . . . . . . . . . . . . . . . . .     2008-2010                 $15,356
                                                                                                        =======
    Federal alternative minimum tax credit carryforwards  . . . . . . . .        ---                    $ 1,866
                                                                                                        =------
    Operating loss carryforwards for Mississippi income tax purposes  . .        2010                   $ 9,690
                                                                                                        =======
    Operating loss carryforwards for Louisiana income tax purposes  . . .     2005-2011                 $ 8,784
                                                                                                        =======
</TABLE>





                                       42
<PAGE>   43
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


6.  ACQUISITIONS

         On August 18, 1995, the Company acquired from a third party
approximately 93% of the working interests in a unitized oil field containing
11 active wells and 159 inactive wells located in the Brookhaven field in
Mississippi (the "Brookhaven Acquisition").  The total cost of the acquisition
is $5.6 million in cash as follows: $1.4 million paid on the acquisition date:
$1.9 million due in August 1996 and $2.3 million due in August 1997.  The net
cost was $5.1 million net of discount based on an imputed interest rate of
8.13% for the promissory notes due in 1996 and 1997.  Only the $1.4 million
cash portion of the acquisition cost is reflected in the consolidated statement
of cash flows for the year ended December 31, 1995 (the year of acquisition).

         On December 8, 1994, the Company acquired all of the capital stock of
ING.  ING, through its subsidiaries, was a privately held natural gas producer,
gatherer and pipeline company operating in Louisiana and Mississippi.
Consideration paid by the Company for the acquisition of ING was $20 million
cash, 2,775,000 common shares of the Company and 161,250 shares of redeemable
preferred stock having an aggregate stated value of $16,125,000.  The
acquisition of ING was accounted for using the purchase method.  Also, see Note
2, "Discontinued Operations" regarding the disposition of the marketing and
transportation segment.

         The following unaudited pro forma  information of the Company  for the
year ended December 31, 1994, has been prepared assuming the ING acquisition
occurred on January 1, 1994.  Such pro forma information is not necessarily
indicative of what actually could have occurred had the acquisition taken place
on January 1, 1994 and excludes the restructuring charges described in note 12.
<TABLE>
<CAPTION>
                                                                       1994
                                                                       ----
<S>                                                                  <C>
Revenues  . . . . . . . . . . . . . . . . . . . . . . . . . .        $ 38,602
Net earnings from continuing operations . . . . . . . . . . .             599
Net earnings  . . . . . . . . . . . . . . . . . . . . . . . .           1,175
Net earnings applicable to common stock . . . . . . . . . . .             150
Earnings (loss) per common share:
   Net earnings (loss) from continuing operations . . . . . .        $  (0.01)
   Net earnings   . . . . . . . . . . . . . . . . . . . . . .        $   0.01
</TABLE>


7.  REDEEMABLE PREFERRED STOCK

         The redeemable preferred stock issued in connection with the
acquisition of ING was non-voting and entitled to receive cumulative quarterly
dividends at a coupon rate equal to the prime lending rate per annum (8.5% for
the first quarter of 1995 and 9% for the second and third quarters of 1995).
If the preferred stock were not redeemed by September 4, 1995, the coupon rate
increased 1/2% per quarter to a maximum rate of 18% per annum.  On August 30,
1995, the Company exchanged 3,225,000 shares of Common Stock for the 161,250
shares of Series A Preferred Stock with a stated value of $16,125,000 and
issued 157,338 shares of Common Stock to the holders of the preferred stock to
satisfy the accrued dividend obligation through August 30, 1995 of $944,000. 
These noncash transactions are not reflected in the consolidated statement of 
cash flows for the year ended December 31, 1995.





                                       43
<PAGE>   44
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

8.  STOCK-BASED COMPENSATION

         Options to purchase the Company's common stock have been 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 Company's subsidiaries in the 1993 Reorganization.  The stock option plans
provide for the issuance of five year options with a three year vesting period
and a grant price equal to or above market value.  A summary of the status of
the Company's stock option plans at December 31, 1994, 1995 and 1996 and
changes during the years then ended follows:

<TABLE>
<CAPTION>
                                                      1994                     1995                       1996           
                                           -------------------------- ------------------------- -------------------------
                                                           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                      1,212,230         5.83  1,533,813         5.63   1,700,313            5.56
    Granted   . . . . . . . . . . . . .         380,000         4.99    166,500         4.98     202,000            5.19
    Exercised   . . . . . . . . . . . .            (623)        3.48        ---          ---     (81,863)           5.05
    Cancelled   . . . . . . . . . . . .         (57,794)        5.06        ---          ---      (4,666)           5.43
                                              ---------         ----  ---------         ----   ---------            ----
Outstanding at December 31  . . . . . .       1,533,813         5.63  1,700,313         5.56   1,815,784            5.55
                                              ---------         ----  ---------         ----   ---------            ----
Exercisable at December 31  . . . . . .         652,657         5.85  1,048,402         5.75   1,390,118            5.69
Available for grant at December 31  . .         243,170                  39,670                  118,836
</TABLE>

         Significant option groups outstanding at December 31, 1996 and related
weighted average price and life information follows:

<TABLE>
<CAPTION>                                                                           WTD AVG
                                    OPTIONS                OPTIONS                  EXERCISE            REMAINING
    GRANT DATE                    OUTSTANDING             EXERCISABLE                 PRICE            LIFE (YEARS)
    ----------                    -----------             -----------                 -----            ------------
<S>                                 <C>                     <C>                        <C>             <C> 
June 13, 1996                        12,000                     ---                    6.63                  5
February 22, 1996                   150,000                     ---                    5.13                  6
January 8, 1996                      40,000                     ---                    5.00                  6
September 25, 1995                   50,000                  33,333                    5.00                  5
September 12 ,1995                   58,000                  19,338                    5.00                  6
August 3, 1995                       24,000                  24,000                    4.88                  5
April 14, 1995                       32,500                  10,834                    5.00                  5
December 4, 1994                    105,000                  38,333                    5.01                  6
November 10, 1994                   240,000                 159,996                    5.00                  5
June 7, 1994                        115,741                 115,741                    5.65                  4
March 28, 1994                        5,000                   5,000                    4.50                  3
October 22, 1993                    406,089                 406,089                    6.00                  4
September 29, 1993                  105,067                 105,067                    6.84                  3
November 18, 1992                     9,999                   9,999                    5.25                  2
October 19, 1992                    462,388                 462,388                    5.61                  2
</TABLE>


The weighted average fair value at date of grant for options granted during
1995 and 1996 was $2.25 and $2.21 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:





                                       44
<PAGE>   45
<TABLE>
<CAPTION>
                                             1995           1996
                                             ----           ----
<S>                                        <C>            <C>
Expected life (years) . . . . . .              5              5
Interest rate . . . . . . . . . .           6.28%          5.37%
Volatility  . . . . . . . . . . .          43.43%         38.79%
Dividend yield  . . . . . . . . .             ---            ---
</TABLE>

         Had compensation cost for these plans been determined consistent with
FASB Statement No. 123, the Company's pro forma net income and earnings per
share from continuing operations would have been as follows:
<TABLE>
<CAPTION>
                                                                           1995             1996
                                                                           ----             ----
<S>                       <C>                                             <C>             <C>
Net income (loss)                 As reported . . . . . . . . .            $169           $5,906
                                  Pro forma . . . . . . . . . .            $(67)          $5,625

Income (loss) per share           As reported . . . . . . . . .            $.01           $  .29
                                  Pro forma . . . . . . . . . .            $ --           $  .27
</TABLE>


9.  COMMITMENTS AND CONTINGENCIES

         (a)   In July, 1994, the Company, together with several other
companies, was named as a defendant in  a lawsuit filed in Jones County,
Mississippi.  The lawsuit, involves claims by a landowner for purported damages
caused by naturally occurring radioactive materials at various wellsite
locations on land leased by the Company in Mississippi.  The plaintiff  is
seeking significant compensatory and punitive damages, including damages for
"emotional distress." This lawsuit has been dormant for two years and the land
involved has been remediated.

         Additionally, in 1996 the Company, together with several other
companies, was named as a defendant in a number of lawsuits of the same nature
as the July, 1994 lawsuit.  All of the suits are principally identical and seek
damages for land damage, health hazard, mental and emotional distress, etc.
None of the suits seek specific award amounts, but all seek punitive damages.

         In January 1996, the Company was named a defendant in a lawsuit filed
in the Circuit Court of Jasper County, Mississippi.  The lawsuit stems from the
accidental death of an employee of an independent contractor doing work for the
Company in late 1995.  The plaintiffs are seeking compensatory and punitive
damages.  A subsequent lawsuit was filed by another employer of the independent
contractor for injuries allegedly sustained during the accident.

         While the Company is not able to determine its exposure in the
remaining suits at this time, the Company believes that the claims will have no
material adverse effect on its financial position or results of operations.

         The Company is involved in various other legal actions arising in the
ordinary course of business.  While it is not feasible to predict the ultimate
outcome of these actions or those listed above, management believes that the
resolution of these matters will not have a material adverse effect, either
individually or in the aggregate, on the Company's financial position or
results of operations.





                                       45
<PAGE>   46
         (b)  The Company has leased (i) 33,261 square feet of office space in
Dallas, Texas under a non-cancellable lease extending through October 2000,
(ii) 5,000 square feet of office space in Laurel, Mississippi under a non-
cancellable lease extending through June 2000, and (iii) various vehicles under
non-cancellable leases extending through March 1999.  Rental expense totalled
$321,000, $487,000 and $694,000 in 1994, 1995 and 1996, respectively.  Minimum
rentals payable under these leases for each of the next five years are as
follows: 1997 - $674,000; 1998 - $603,000; 1999 - $556,000; 2000 - $449,000 and
2001 - $0.  Total rentals payable over the remaining terms of the leases are
$2,282,000.

         (c)  Like other crude oil and natural gas producers, the Company's
operations are subject to extensive and rapidly changing federal, state and
local environmental regulations governing emissions into the atmosphere, waste
water discharges, solid and hazardous waste management activities, noise levels
and site restoration and abandonment activities. 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 $3,000,000,
excluding the Monroe gas field discussed below.  A total of $928,000 has been
included in depletion and depreciation expense with respect to such costs as of
December 31, 1996.

         Certain governmental agencies are presently studying whether the oil
and gas industry's practice of utilizing mercury meters poses any potential
environmental problems that require more stringent regulation.  Operators in
the Monroe Field have been asked to monitor their operations and assist in
gathering data.  During 1995, the Company voluntarily negotiated a remediation
plan with the governmental agencies responsible for the two wildlife refuges in
the Monroe Field.  Under the plan, the Company began removal of the mercury
meters within the two wildlife refuges in 1996.  The Company continues to
cooperate with the various agencies in their studies.  At this time, the
Company believes that minor mercury spillages and leaks may have occurred in
the past.  However, the Company believes that such spillages and leaks are less
than the amounts reportable under prior or existing statues and laws.  The
Company makes a provision for future site restoration charges on a
unit-of-production basis for the Monroe field gas which is included in
depletion and depreciation expense; a total of $705,000 has been included in
depletion and depreciation expense with respect to such costs as of December
31, 1996.

         (d)  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
total annual compensation of the officer in the event the officer's employment
is terminated for other than cause.  If the officer's employment is terminated
for other than cause following a change in control in the Company, the officer
generally is entitled to a severance payment in the amount of 2.99 times the
rate of total annual compensation of the officer.

         The officers' aggregate base salary and bonus portion of total annual
compensation covered under such employment agreements is approximately $1.3
million.

         (e)  The Company has entered into executive severance agreements with
most of its other officers which are designed  to encourage executive officers
to continue to carry out their duties with the Company in the event of a change
in control of the Company.  In the event of the officer's employment is
terminated for other than cause following a change of control, these severance
agreements generally provide for a severance payment in an amount equal to 1.5
times the highest salary plus bonus paid to such officer in any of the five
years preceding the year of termination.

         The highest salary plus bonus paid to the officers covered under such
severance agreements during the preceding five year period would aggregate
approximately $851,000.

         (f)  In conjunction with the acquisition of ING and the 1993
reorganization (note 1), the Company has





                                       46
<PAGE>   47
granted certain persons the right to require the Company, at its expense, to
register their shares under the Securities Act of 1933.  These registration
rights may be exercised on up to 5 occasions.  The number of shares of Common
Stock subject to registration rights as of December 31, 1996, is approximately
6,157,000.


10.  FINANCIAL INSTRUMENTS AND CREDIT RISK CONCENTRATIONS

         Financial instruments which are potentially subject to concentrations
of credit risk consist principally of cash, cash equivalents and accounts
receivable. Cash and cash equivalents are placed with high credit quality
financial institutions to minimize risk.  The carrying amounts of these
instruments approximate fair value because of their short maturities.  The
Company has entered into certain financial arrangements which act as a hedge
against price fluctuations in future crude oil and natural gas production.
Included in operating revenues are gains (losses) of $1,075,000; $441,000 and
$(5,908,000) for 1994, 1995 and 1996, respectively, resulting from these
hedging programs.  At December 31, 1996, the Company has 15,000 Mmbtu per day
of natural gas production hedged for the months January through March 1997, at
an average price of $3.07 per Mmbtu.  The Company has also entered into certain
arrangements which fix a minimum West Texas Intermediate ("WTI") price per
barrel of $18.00 and a maximum WTI price of $21.30 for 4,000 barrels of oil
production per day for the period January 1, 1997 through June 30, 1997 and
arrangements which fix an average  WTI price of $23.47 for 3,000 barrels of oil
production per day for the period January 1, 1997 through March 31, 1997.  At
December 31, 1995 and 1996, the Company had deferred hedging losses of $335,000
and $-0-, respectively, attributable to crude oil and natural gas production.

         The stated value of long term debt approximates fair market value
since the interest applicable to each instrument approximates market rates.

         During the year ended December 31, 1996, two purchasers of Coho's
crude oil and natural gas, EOTT Energy Corp.  ("EOTT") and Mid Louisiana
Marketing Company (formerly a wholly owned subsidiary sold on April 3, 1996 -
see note 2), accounted for 66% and 15%, respectively, of Coho's receipt of
operating revenues.  In 1994 and 1995 Amerada Hess Corporation ("Amerada")
accounted for 64% and 66%, respectively, of Coho's receipt of operating
revenues  Included in accounts receivable is $1,767,000; $2,691,000 and
$7,222,491 due from these customers at December 31, 1994, 1995 and 1996,
respectively.





                                       47
<PAGE>   48
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

11.  RELATED PARTY TRANSACTIONS

         (a)  Corporations controlled by certain directors, officers and
shareholders of the Company have participated with the Company in certain crude
oil and natural gas joint ventures on the same terms and conditions as other
industry partners. These transactions are summarized as follows:

<TABLE>
<CAPTION>
                                                                        1994       1995       1996
                                                                        ----       ----       ----
 <S>                                                                     <C>       <C>     <C>         
    Campco International Capital Ltd. (i)
         Net crude oil and natural gas revenues . . . . . . . .          $94      $219       $243
         Capital expenditures . . . . . . . . . . . . . . . . .           96        77        101
         Payable to (receivable from) CRI at the balance
           sheet date . . . . . . . . . . . . . . . . . . . . .           26        (3)       (22)


    (i)  Campco International Capital Ltd. is a private company controlled by
         Frederick K. Campbell, a director of the Company.

</TABLE>


         (b)  In 1990, the Company made a non-interest bearing loan in the
amount of $205,000 to Jeffrey Clarke, President, Chief Executive Officer and
Director of the Company, to assist him in the purchase of a house in Dallas.
The loan is unsecured, is repayable on the date Mr. Clarke ceases employment
with the Company and is included in other assets at December 31, 1996.

         (c)  Certain of the Company's hedging agreements are with an affiliate
of the Company, Morgan Stanley Capital Group, which owns over 10% of the
Company's outstanding common stock.  Management of the Company believes that
such transactions are on similar terms as could be obtained from unrelated
third parties.


12.  RESTRUCTURING EXPENSES

         Subsequent to the acquisition of ING, the Company reviewed the
operations of the combined companies and identified opportunities to reduce
administrative overhead and operating costs beyond the scope contemplated when
the acquisition was made.  In conjunction with the development and
implementation  of a plan to effect these cost savings, the Company has
recorded a charge of $2,494,000 ($1,521,000 of which is included in
discontinued operations - see note 2) in the 1994 consolidated financial
statements representing employee benefits, severance and outplacement service
payments for 23 executive and administrative positions and 19 operating
positions (primarily pipeline positions).  During 1995 and 1996, the Company
effectuated all 42 terminations and paid termination benefits totalling
$2,062,000 and $412,000, respectively.





                                       48
<PAGE>   49
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


13. CASH FLOW INFORMATION

    Supplemental cash flow information is presented below:

<TABLE>
<CAPTION>
                                                     1994      1995       1996
                                                     ----      ----       ----
<S>                                              <C>          <C>       <C>
Cash paid (received) during the period for:
   Interest . . . . . . . . . . . . . . . . .     $ 4,118      $ 7,574   $ 8,259
   Income taxes . . . . . . . . . . . . . . .     $   (11)     $(1,131)  $   478
</TABLE>

14. CANADIAN ACCOUNTING PRINCIPLES

    These financial statements have been prepared in conformity with generally
accepted accounting principles ("GAAP") as presently established in the United
States.  These principles differ in certain respects from those applicable in
Canada.  These differences would have affected net earnings (loss) as follows:

<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31    
                                                                    ---------------------------------
                                                                       1994        1995        1996   
                                                                    ---------    --------     -------
<S>                                                                 <C>         <C>           <C>
Net earnings (loss) based on US GAAP  . . . . . . . . . . . . .     $ (1,654)   $  1,780      $ 5,096
Adjustment to depletion based on difference in carrying value
of oil and gas properties related to:

   ING acquisition (i)  . . . . . . . . . . . . . . . . . . . .           55         576          556

   Business combination with Odyssey Exploration, Inc. in               (211)       (198)        (178)
     1990

   Application of Canadian full cost ceiling test . . . . . . .         (569)       (535)        (482)

Deferred tax effect of adjustment above . . . . . . . . . . . .          246          53           35
                                                                    --------    --------      -------
Net earnings (loss) based on Canadian GAAP  . . . . . . . . . .     $ (2,133)   $  1,676      $ 5,027
                                                                    ========    ========      =======
Net earnings (loss) per common share based on Canadian GAAP . .     $  (0.15)   $   0.09      $  0.25  
                                                                    ========    ========      =======
                                                                                                      
</TABLE>





                                       49
<PAGE>   50
                                COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


    The effect on the consolidated balance sheets of the differences between
United States and Canadian GAAP is as follows:
<TABLE>
<CAPTION>
                                                                                                    UNDER
                                                           AS                INCREASE             CANADIAN
                                                        REPORTED            (DECREASE)               GAAP
                                                        --------            ----------            ---------
<S>                                                     <C>                 <C>                    <C>
DECEMBER 31, 1996
-----------------

Property and Equipment  . . . . . . . . .               $210,212            $ 2,191                $212,403
Deferred Income Taxes . . . . . . . . . .                 14,842             (4,769)                 10,073
Shareholder's Equity  . . . . . . . . . .                 81,466              6,961                  88,427

DECEMBER 31, 1995
-----------------

Property and Equipment  . . . . . . . . .               $175,899             $2,295                $178,194
Deferred Income Taxes . . . . . . . . . .                 11,009             (4,733)                  6,276
Shareholder's Equity  . . . . . . . . . .                 74,321              7,029                  81,350
</TABLE>

    (i)  Under FAS 109 in the United States, the Company was required to
increase deferred income taxes and property and equipment by $8,355,000 for the
deferred tax effect of the excess of the Company's tax basis of the stock
acquired in the ING acquisition over the tax basis of the net assets of ING
acquired (note 6).  Under Canadian GAAP this adjustment is not required.





                                       50
<PAGE>   51
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

15. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
                                                       FIRST       SECOND       THIRD       FOURTH       TOTAL
                                                       -----       ------       -----       ------       -----
<S>                                                   <C>         <C>          <C>         <C>          <C>
1996
   Operating revenues . . . . . . . . . . . . . .     $12,367     $12,938      $13,552     $15,415      $54,272
   Operating income . . . . . . . . . . . . . . .       3,576       3,738        4,182       5,357       16,853
   Net earnings . . . . . . . . . . . . . . . . .       1,035       1,103        1,326       2,442        5,906
   Net earnings per share . . . . . . . . . . . .     $   .05     $   .06      $   .06     $   .12      $   .29

1995
   Operating revenues . . . . . . . . . . . . . .     $ 9,402     $10,000      $10,418     $11,083      $40,903
   Operating income . . . . . . . . . . . . . . .       1,574       1,321        1,913       3,521        8,329
   Income (loss) from continuing operations . . .        (140)       (361)        (147)        817          169
   Income (loss) from discontinued operations . .         317          26          113       1,155        1,611
   Net earnings (loss)  . . . . . . . . . . . . .         177        (335)         (34)      1,972        1,780
   Net earnings (loss) per share:
    Continuing Operations   . . . . . . . . . . .     $ (0.02)    $ (0.03)     $ (0.02)    $  0.04      $ (0.02)
    Discontinued operations   . . . . . . . . . .        0.01       (0.01)        0.00        0.06         0.07
                                                      -------     --------     -------     -------      -------
    Net income (loss) per share   . . . . . . . .     $ (0.01)    $ (0.04)     $ (0.02)    $  0.10      $  0.05
                                                      =======     =======      =======     =======      =======

1994
   Operating revenues . . . . . . . . . . . . . .     $ 5,814     $ 6,280      $ 6,464     $ 7,906      $26,464
   Operating income . . . . . . . . . . . . . . .         766         824          968         137        2,695
   Income (loss) from continuing operations . . .          68         (24)         (85)       (933)        (974)
   Income (loss) from discontinued operations . .         ---         ---          ---        (680)        (680)
   Net earnings (loss)  . . . . . . . . . . . . .          68         (24)         (85)     (1,613)      (1,654)
   Net earnings (loss) per share:
    Continuing operations   . . . . . . . . . . .     $  0.00     $  0.00      $ (0.01)    $ (0.07)     $ (0.07)
    Discontinued operations   . . . . . . . . . .         ---         ---          ---       (0.05)       (0.05)
                                                      -------     -------      -------     --------     --------
    Net income (loss) per share)  . . . . . . . .     $  0.00     $  0.00      $ (0.01)    $ (0.12)     $ (0.12)
                                                      =======     =======      =======     ========     ========
</TABLE>


    The per share figures are computed based on the weighted average number of
shares outstanding for each period shown.





                                       51
<PAGE>   52

                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

16. SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS ACTIVITIES

(a) COSTS INCURRED

    Costs incurred for property acquisition, exploration and development
activities were as follows:
<TABLE>
<CAPTION>
                                                                           1994       1995         1996
                                                                           ----       ----         ----
    <S>                                                                 <C>                    <C>
    Property acquisitions
         Proved . . . . . . . . . . . . . . . . . . . . . . . . . .     $  52,277  $   7,294    $   1,139
         Unproved . . . . . . . . . . . . . . . . . . . . . . . . .           692      2,253          986
    Exploration   . . . . . . . . . . . . . . . . . . . . . . . . .         1,099      3,378        6,528
    Development   . . . . . . . . . . . . . . . . . . . . . . . . .        16,469     19,194       41,091
    Other   . . . . . . . . . . . . . . . . . . . . . . . . . . . .           305        677          894
                                                                        ---------  ---------    ---------
                                                                        $  70,842  $  32,796    $  50,638
                                                                        =========  =========    =========
    Property and equipment , net of accumulated depletion.  . . . .     $ 157,170  $ 175,899    $ 210,212
                                                                        =========  =========    =========
</TABLE>





                                       52
<PAGE>   53
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

(b) 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. 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, 1993   . . . . . . . . . . . . .     24,892      14,064
    Revisions of previous estimates   . . . . . . . . . . . . . . . . .      1,053        (205)
    Purchase of reserves in place   . . . . . . . . . . . . . . . . . .        373      86,928
    Extensions and discoveries  . . . . . . . . . . . . . . . . . . . .      3,174         ---
    Production  . . . . . . . . . . . . . . . . . . . . . . . . . . . .     (1,977)       (670)
                                                                            -------       -----

    Estimated reserves at December 31, 1994   . . . . . . . . . . . . .     27,515     100,117
    Revisions of previous estimates   . . . . . . . . . . . . . . . . .       (599)     14,639
    Purchase of reserves in place   . . . . . . . . . . . . . . . . . .      1,786           9
    Extensions and discoveries  . . . . . . . . . . . . . . . . . . . .      4,274         200
    Production  . . . . . . . . . . . . . . . . . . . . . . . . . . . .     (2,178)     (7,093)
                                                                            -------     -------

    Estimated reserves at December 31, 1995   . . . . . . . . . . . . .     30,798     107,872
    Revisions of previous estimates   . . . . . . . . . . . . . . . . .     (1,913)     10,335
    Purchase of reserves in place   . . . . . . . . . . . . . . . . . .        218         ---
    Extensions and discoveries  . . . . . . . . . . . . . . . . . . . .      8,186       1,571
    Production  . . . . . . . . . . . . . . . . . . . . . . . . . . . .     (2,467)     (6,646)
                                                                            -------     -------
    Estimated reserves at December 31, 1996   . . . . . . . . . . . . .     34,822     113,132
                                                                            ======     =======
    Proved developed reserves at December 31,
         1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     19,800      87,166
         1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     23,478      94,878
         1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .     24,089      98,936
</TABLE>





                                       53
<PAGE>   54
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


(c) 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 Financial Accounting Standards Board Statement 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 its simplistic use.

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

<TABLE>
<CAPTION>
                                                                                 1994          1995          1996
                                                                                 ----          ----          ----
   <S>                                                                           <C>          <C>          <C>
   Future cash inflows  . . . . . . . . . . . . . . . . . . . . . . . . . .      $511,689     $ 766,196    $1,174,356
   Future production costs  . . . . . . . . . . . . . . . . . . . . . . . .      (196,374)     (234,309)     (301,619)
   Future development costs . . . . . . . . . . . . . . . . . . . . . . . .       (34,095)      (33,824)      (52,769)
                                                                                 --------     ---------    ----------  
   Future net cash flows before income taxes  . . . . . . . . . . . . . . .       281,220       498,063       819,968
   Annual discount at 10% . . . . . . . . . . . . . . . . . . . . . . . . .      (116,811)     (229,445)     (402,885)
                                                                                 --------     ---------    ----------  
   Present value of future net cash flows before income taxes
    ("Present Value of Proved Reserves")  . . . . . . . . . . . . . . . . .       164,409       268,618       417,083
   Future income taxes discounted at 10%  . . . . . . . . . . . . . . . . .       (29,390)      (43,679)      (79,864)
                                                                                 --------     ---------    ----------  
   Standardized measure of discounted future net cash flows . . . . . . . .      $135,019     $ 224,939    $  337,219
                                                                                 ========     =========    ==========

   December 31 West Texas Intermediate posted price ($ per Bbl) . . . . . .      $  16.00     $   18.00    $    25.25
   Estimated December 31 Company average realized price
    $/Bbl   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      $  13.01     $   15.69    $    22.02
    $/Mcf   . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .      $   1.58     $    2.54    $     3.53
</TABLE>




                                       54
<PAGE>   55
                               COHO ENERGY, INC.
                                AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)



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


<TABLE>
<CAPTION>
                                                                     1994         1995        1996
                                                                     ----         ----        ----
<S>                                                                <C>         <C>          <C>
Crude oil and natural gas sales, net of production costs  . .      $(17,092)   $(28,446)    $(46,305)
Net changes in anticipated prices and production costs  . . .        29,548      93,551      128,960
Extensions and discoveries, less related costs  . . . . . . .        11,002      24,281       74,560
Changes in estimated future development costs . . . . . . . .        (9,474)    (10,581)      (2,580)
Development costs incurred during the period  . . . . . . . .        16,469      19,194        6,321
Net change due to sales and purchase of reserves in place . .        50,741      10,409        1,108
Accretion of discount . . . . . . . . . . . . . . . . . . . .         8,111      16,441       26,862
Revision of previous quantity estimates . . . . . . . . . . .         6,086      11,768       (1,643)
Net changes in income taxes . . . . . . . . . . . . . . . . .       (20,824)    (14,289)     (36,185)
Changes in timing of production and other . . . . . . . . . .       (12,091)    (32,408)     (38,818)
                                                                   --------    --------     --------
Net increase (decrease) . . . . . . . . . . . . . . . . . . .        62,476      89,920      112,280
Beginning of year . . . . . . . . . . . . . . . . . . . . . .        72,543     135,019      224,939
                                                                   --------    --------     --------
End of year . . . . . . . . . . . . . . . . . . . . . . . . .      $135,019    $224,939     $337,219
                                                                   ========    ========     ========
</TABLE>





                                       55
<PAGE>   56
ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
         ACCOUNTING AND FINANCIAL DISCLOSURE

   NONE


                                    PART III


ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

ITEM 11.  EXECUTIVE COMPENSATION

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

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

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

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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





                                       56
<PAGE>   57
                                    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 29.

2.   FINANCIAL STATEMENT SCHEDULES
                                                                            PAGE
                                                                            ----

     Independent Auditors' Reports  . . . . . . . . . . . .. . . . . . . . .  61
     Schedule I --Condensed Financial Information - Parent Only. . . . . . .  63

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

3.   EXHIBITS

<TABLE>
<CAPTION>
            EXHIBIT
            NUMBER                 DESCRIPTION
            ------                 -----------
             <S>      <C>
             2.1      - Plan of Reorganization dated as of June 30, 1993, by and among the Registrant, Coho Resources,
                        Inc.,  a Nevada corporation, and Coho Resources Limited, an Alberta, Canada corporation
                        (incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4
                        (Reg. No. 33-65620)).

             3(i).1   - Articles of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the
                        Company's Registration Statement on Form S-4 (Registration No. 33-65620)).

             3(i).2   - Statement of Resolution Establishing Series of Shares of Series A Preferred Stock dated December
                        8, 1994 (incorporated by reference to the Company's Form 8-K filed on December 16, 1984).

             3(i).3   - First Amendment to Statement of Resolution Establishing Series of Shares of Series A Preferred
                        Stock dated August 23, 1995 (incorporated by reference to Exhibit 3(i).1 to the Company's
                        Quarterly Report  on Form 10-Q for the quarter ended September 30, 1995).

             3(ii).1  - Bylaws of the Company, filed as Exhibit 3.2 to the Company's Registration Statement on Form S-4
                        (Registration No. 33-65620) and incorporated by reference herein.

             4.1      - Articles of Incorporation (included as Exhibit 3(i).1 above).

             4.2      - Statement of Resolution Establishing Series of Shares (included as Exhibit 3(i).2 above).

             4.3      - Bylaws of the Company (included as Exhibit 3(ii).1 above).
</TABLE>





                                       57
<PAGE>   58
<TABLE>
             <S>      <C>
             4.4      - Rights Agreement dated September 13, 1994 between Coho Energy, Inc. and Chemical Bank
                        (incorporated by reference to Exhibit 1 to the Company's Form 8-A dated September 13, 1994).

             4.5      - First Amendment to Rights Agreement made as of December 8, 1994 between Coho Energy, Inc. and
                        Chemical Bank (incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form
                        10-K for the year ended December 31, 1994).

             4.6      - Second Amendment to Rights Agreement as of August 30, 1995 between Coho Energy, Inc. and
                        Chemical Bank (incorporated by reference to Exhibit 4.1 to the Company's Quarterly Report on
                        Form 10-Q for the quarter ended September 30, 1995).

              10.1    - Registration Rights and Shareholder Agreement dated December 8, 1994 by and among Coho Energy,
                        Inc., The Morgan Stanley Leveraged Equity Fund II, LP, and Quinn Oil Company Ltd (incorporated
                        by reference to Exhibit 10.2 to the Company's Annual Report on Form 10-K for the year ended
                        December 31, 1994).

              10.2    - Amended and Restated Registration Rights Agreement dated December 8, 1994 among Coho Energy,
                        Inc., Kenneth H. Lambert and Frederick K. Campbell (incorporated by reference to Exhibit 10.3 to
                        the Company's Annual Report on Form 10-K for the year ended December 31, 1994).

             *10.3    - 1993 Stock Option Plan (incorporated by reference to Exhibit 10.1 to the Company's Registration
                        Statement on Form S-4 (Reg. No. 33-65620)).

             *10.4    - First Amendment to 1993 Stock Option Plan (incorporated by reference to Exhibit 10.6 to the
                        Company's  Quarterly Report on Form 10-Q for the quarter ended September 30, 1993).

             *10.5    - Second Amendment and Third Amendment to 1993 Stock Option Plan (incorporated by reference to
                        Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994).

             *10.6      Third Amendment to 1993 Stock Option Plan (incorporated by reference to Exhibit 10.2 to the
                        Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996).

             *10.7    - Employment Agreement dated as of November 11, 1994 by and between Coho Energy, Inc. and Jeffrey
                        Clarke (incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K
                        for the year ended December 31, 1994).

             *10.8    - Employment Agreement dated as of November 11, 1994 by and between Coho Energy, Inc. and R. M.
                        Pearce (incorporated by reference to Exhibit 10.8 to the Company's Annual Report Form 10-K for
                        the year ended December 31, 1994).

             *10.9    - Employment Agreement dated as of June 25, 1995 by and between Eddie M. LeBlanc, III and Coho
                        Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on
                        Form 10-Q for the quarterly period ended June 30, 1995).

             *10.10     Employment Agreement dated as of August 19, 1996 by and between Anne Marie O'Gorman and Coho 
                        Energy, Inc.

             *10.11     First Amendment to Employment Agreement dated as of August 19, 1996 by and among Jeffrey Clarke 
                        and Coho Energy, Inc.

             *10.12     First Amendment to Employment Agreement dated as of August 19, 1996 by and among R. M. Pearce 
                        and Coho Energy, Inc.

             *10.13     First Amendment to Employment Agreement dated as of August 19, 1996 by and among 
                        Eddie M. LeBlanc, III and Coho Energy, Inc.

             10.14      Third Amended and Restated Credit Agreement among Coho Resources, Inc., Coho Louisiana Production 
                        Company, Coho Exploration, Inc., Coho Energy, Inc., Bank Paribas, Houston

</TABLE>





                                       58
<PAGE>   59
<TABLE>
             <S>      <C>
                        Agency, Bank One, Texas, N.A., and Meespierson N.V. dated as of August 8, 1996 (incorporated by
                        reference to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
                        1996).

             *10.15   - 1993 Non Employee Director Stock Option Plan (incorporated by reference to Exhibit 10.2 to the
                        Company's Registration Statement on Form S-4 (Reg. No. 33-65620)

             *10.16     First Amendment to 1993 Non-Employee Director Stock Option Plan (incorporated by reference to
                        Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
                        1996).

             *10.17   - Form of Executive Severance Agreement entered into with each of Keri Clarke, R. Lynn Guillory,
                        Larry L. Keller, Susan J. McAden, and Patrick S. Wright (incorporated by reference to Exhibit
                        10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995).

             *10.18     Stock Purchase Agreement dated March 4, 1996 among Coho Energy, Inc., Interstate Natural Gas
                        Company, and Republic Gas Partners, L. L. C. (incorporated by reference to the Exhibit 10.16 to
                        the Company's Annual Report on Form 10-K for the year ended December 31, 1995.

              10.19   - 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 From 10-K for the year ended December 31, 1995).

              10.20     Gas Purchase Contract dated January 1, 1996, by and between Mid Louisiana Production Company and
                        Mid Louisiana Marketing Company (incorporated by reference to Exhibit 99.1 to the Company's
                        current report on Form 8-K dated April 3, 1996).

              10.21     Gas Transportation Agreement dated January 1, 1996, by and between Mid Louisiana Gathering
                        Company and Mid Louisiana Marketing Company (incorporated by reference to Exhibit 99.2 to the
                        Company's current report on Form 8-K dated April 3, 1996).

              10.22     Gas Transportation Agreement dated January 1, 1996, by and between Fairbanks Gathering Company
                        and Mid Louisiana Marketing Company (incorporated by reference to Exhibit 99.3 to the Company's
                        current report on Form 8-K dated April 3, 1996).

              11.1    - Statement re computation of per share earnings.

              21.1    - List of Subsidiaries of the Company.

              23.1    - Consent of KPMG Peat Marwick LLP.

              23.2    - Consent of Arthur Andersen LLP.

              27      - Financial Data Schedule
</TABLE>
---------------

*  Represents management contract or compensatory plan or arrangement.

             The Company will furnish a copy of any exhibit described above to
any beneficial holder of its securities





                                       59
<PAGE>   60
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
1996 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





                                       60
<PAGE>   61
                   REPORT FOR INDEPENDENT PUBLIC ACCOUNTANTS



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


    Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole.  The information contained in Schedule
III is not a required part of the basic financial statements but is
supplementary information required by the Securities and Exchange Commission.
This information has been subjected to the auditing procedures applied in the
audit of the basic financial statements and, in our opinion, is fairly stated
in all material respects in relation to the basic financial statements taken as
a whole.

                                        Arthur Andersen LLP


Dallas, Texas
February 21, 1997





                                       61
<PAGE>   62
                          INDEPENDENT AUDITORS' REPORT



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

    Under date of February 24, 1995 we reported on the consolidated statements
of earnings, shareholders' equity and cash flows of Coho Energy, Inc. and
subsidiaries for the year ended December 31, 1994, which are included in this
annual report on Form 10-K. In connection with our audit of the aforementioned
consolidated financial statements, we also audited the accompanying related
financial statement schedule as listed in Item 14.  The financial statement
schedule is the responsibility of the Company's management.  Our responsibility
is to express an opinion on this financial statement schedule based on our
audit.

    In our opinion, such schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.

                                        KPMG Peat Marwick LLP



Dallas, Texas
February 24, 1995





                                       62
<PAGE>   63
-                                                                    

                               COHO ENERGY, INC.
                                AND SUBSIDIARIES

                                  SCHEDULE III

                 CONDENSED FINANCIAL INFORMATION - PARENT ONLY

     The following presents the condensed balance sheets as of December 31,
1996 and 1995 and statements of earnings and statements of cash flows for Coho
Energy, Inc., the parent company, for the years ended December 31, 1996, 1995
and 1994.



                               COHO ENERGY, INC.
                                    (PARENT)
                            CONDENSED BALANCE SHEETS
               (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)

                                    ASSETS
<TABLE>
<CAPTION>
                                                                   DECEMBER 31
                                                                   -----------
                                                                1995        1996
                                                                ----        ----
<S>                                                          <C>        <C>

CURRENT ASSETS

     CASH AND CASH EQUIVALENTS ...........................   $      3   $    304

     DUE FROM SUBSIDIARIES ...............................      7,035      7,535
                                                             --------   --------
                                                                7,038      7,839
INVESTMENTS IN SUBSIDIARIES, at equity ...................     67,303     73,632
                                                             --------   --------
                                                             $ 74,341   $ 81,471
                                                             ========   ========

                      LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES

     Accounts payable ....................................   $     20   $      5
                                                             --------   --------

SHAREHOLDERS' EQUITY

     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 20,165,263 and 20,347,126 shares at
          December 31, 1995 and 1996, respectively .......        202        203

     Additional paid-in capital ..........................     82,278     83,516

     Retained earnings (deficit) .........................      8,159)    (2,253)
                                                             --------   --------
     Total shareholders' equity ..........................     74,321     81,466
                                                             --------   --------
                                                             $ 74,341   $ 81,471
                                                             ========   ========
</TABLE>


           SEE ACCOMPANYING NOTES TO CONDENSED FINANCIAL INFORMATION

                                       63



<PAGE>   64



                                                                    SCHEDULE III
                               COHO ENERGY, INC.
                                    (PARENT)
                        CONDENSED STATEMENT OF EARNINGS
               (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)




<TABLE>
<CAPTION>
                                                   DECEMBER 31
                                          -----------------------------
                                            1994       1995       1996
                                            ----       ----       ----
<S>                                       <C>          <C>        <C>

OPERATING EXPENSES

     General and administrative .......   $   409    $   428    $   423

EQUITY IN (INCOME) LOSS OF SUBSIDIARIES     1,245     (2,208)    (6,329)
                                          -------    -------    -------

NET INCOME (LOSS) .....................    (1,654)     1,780      5,906
DIVIDENDS ON PREFERRED STOCK ..........       (86)      (944)       (--)
                                          -------    -------    -------
NET INCOME (LOSS) APPLICABLE TO
COMMON STOCK ..........................   $(1,740)   $   836    $ 5,906
                                          =======    =======    =======
INCOME (LOSS) PER COMMON SHARE ........   $ (0.12)   $  0.05    $   .29
                                          =======    =======    =======
</TABLE>























           See accompanying Notes to Condensed Financial Information


                                       64

<PAGE>   65



                                                                    SCHEDULE III

                               COHO ENERGY, INC.
                                    (PARENT)
                       CONDENSED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)





<TABLE>
<CAPTION>

                                                            YEAR ENDED DECEMBER 31
                                                         -----------------------------
                                                           1994       1995       1996
                                                           ----       ----       ----
<S>                                                      <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES

     Net income (loss) ...............................   $(1,654)   $ 1,780    $ 5,906

     Adjustments to reconcile net income (loss) to net
         provided by operating activities:
           Equity in (income) loss of subsidiaries ...     1,245     (2,208)    (6,329)
           Increase (decrease) in accounts payable ...        88        (94)       (15)
                                                         -------    -------    -------
Net cash used in operating activities ................      (321)      (522)      (438)
                                                         -------    -------    -------
CASH FLOWS FROM INVESTING ACTIVITIES

     Advances from (to) subsidiaries .................       463        466       (325)
                                                         -------    -------    -------
Net cash provided by (used in) investing activities ..       463        466       (325)
                                                         -------    -------    -------
CASH FLOWS FROM FINANCING ACTIVITIES

      Issuance of common stock .......................         2       --         --

      Proceeds from stock options exercised ..........      --         --          414

      Dividends on preferred stock ...................       (86)      --         --
                                                         -------    -------    -------
Net cash provided by (used in) financing activities ..       (84)      --          414
                                                         -------    -------    -------
Increase (decrease) in cash ..........................        58        (56)       301

Cash, at beginning of period .........................         1         59          3
                                                         -------    -------    -------
Cash, at end of period ...............................   $    59    $     3    $   304
                                                         =======    =======    =======
</TABLE>










           See accompanying Notes to Condensed Financial Information

                                       65

<PAGE>   66



                                                             SCHEDULE III
                               COHO ENERGY, INC.
                                    (PARENT)
                    NOTES TO CONDENSED FINANCIAL INFORMATION
              FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996

1.   GENERAL

     The accompanying condensed financial information of Coho Energy, Inc. (the
     "Company") should be read in conjunction with the consolidated financial
     statements of the Company and its subsidiaries included in the Company's
     Annual Report on Form 10-K for the year ended December 31, 1996.


2.   COMMITMENTS AND CONTINGENCIES

     The Registrant has guaranteed $122,800,000 of debt related to
     unconsolidated subsidiaries under the Restated Credit Agreement described
     in note 4 to the consolidated financial statements of the Company.

     The Restated Credit Agreement contains certain financial and other
     covenants including (i) the maintenance of minimum amounts of
     shareholder's equity, (ii) maintenance of minimum ratios of cash flow to
     interest expense, as well as current assets to current liabilities, (iii)
     limitations on the Company's ability to incur additional debt, and (iv)
     restrictions on the payment of dividends. In the event of a change of
     control of the Company, as defined in the Restated Credit Agreement, at
     the discretion of the lenders, the loan may become immediately due and
     payable. At December 31, 1996, the Company was in compliance with all debt
     covenants.


3.   REDEEMABLE PREFERRED STOCK

     The redeemable preferred stock issued in connection with the acquisition
     of a subsidiary corporation was non-voting and entitled to receive
     cumulative quarterly dividends at a coupon rate equal to the prime lending
     rate per annum (8.5% for the first quarter of 1995 and 9% for the second
     and third quarters of 1995). If the preferred stock were not redeemed by
     September 4, 1995, the coupon rate increased 1/2% per quarter to a maximum
     rate of 18% per annum. On August 30, 1995, the Company exchanged 3,225,000
     shares of Common Stock for the 161,250 shares of Series A Preferred Stock
     with a stated value of $16,125,000 and issued 157,338 shares of Common
     Stock to the holders of the preferred stock to satisfy the accrued
     dividend obligation through August 30, 1995 of $944,000. These noncash
     transactions are not reflected in the statement of cash flows for the year
     ended December 31, 1995.

4.   NON CASH INVESTING AND FINANCING ACTIVITIES


         On December 8, 1994, the Company and CRI acquired all of the capital
         stock of Interstate Natural Gas Company. The Company paid the
         following non-cash amounts for its share of the acquisition cost.


<TABLE>
<S>                                                              <C>        
Common Stock (2,775,000 shares)...............................   $13,875,000
Preferred Stock (161,250 shares)..............................    16,125,000
                                                                 -----------
                                                                 $30,000,000
                                                                 ===========
</TABLE>


                                       66

<PAGE>   67



                                   SIGNATURES

         Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
                                       
                                       COHO ENERGY, INC.
                                       
Date: March 13, 1997                   By: (SIGNED) JEFFREY CLARKE
                                            -----------------------
                                             Jeffrey Clarke
                                             Chairman, President 
                                             and Chief Executive Officer

        Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

    SIGNATURE                            TITLE                        DATE
    ---------                            -----                        ----
[S]                               [C]                           [C]    
                                                             
(SIGNED) JEFFREY CLARKE           Chairman, President        
------------------------------      Chief Executive Officer      March 13, 1997
Jeffrey Clarke                      and Director             
                                                             
(SIGNED) EDDIE M. LEBLANC III     Sr. Vice President and     
------------------------------      Chief Financial Officer      March 13, 1997
Eddie M. LeBlanc, III               (principal financial     
                                    and accounting officer)  
                                                             
(SIGNED) ROBERT. B. ANDERSON      Director                       March 13, 1997
------------------------------                               
Robert B. Anderson                                           
                                                             
(SIGNED) ROY R. BAKER             Director                       March 13, 1997
------------------------------                               
Roy R. Baker                                                 
                                                             
(SIGNED) FREDERICK K. CAMPBELL    Director                       March 13, 1997
------------------------------                               
Frederick K. Campbell                                        
                                                             
(SIGNED) LOUIS F. CRANE           Director                       March 13, 1997
------------------------------                               
Louis F. Crane                                               
                                                             
(SIGNED) HOWARD I. HOFFEN         Director                       March 13, 1997
------------------------------                               
Howard I. Hoffen                                             
                                                             
(SIGNED) KENNETH H. LAMBERT       Director                       March 13, 1997
------------------------------                               
Kenneth H. Lambert                                           
                                                             
(SIGNED) DOUGLAS R. MARTIN        Director                       March 13, 1997
------------------------------                               
Douglas R. Martin                                            
                                                             
(SIGNED) CARL S. QUINN            Director                       March 13, 1997
------------------------------                               
Carl S. Quinn                                                
                                                             
(SIGNED) JAKE TAYLOR              Director                       March 13, 1997
------------------------------                               
Jake Taylor                     

                                      67

<PAGE>   68

<TABLE>
<CAPTION>
EXHIBIT
NUMBER                 EXHIBIT
-------                -------
<S>        <C>

 10.10     Employment Agreement


*10.11     First Amendment to Employment Agreement dated as of 
           August 19, 1996 by and among Jeffrey Clarke 
           and Coho Energy, Inc.

*10.12     First Amendment to Employment Agreement dated as of 
           August 19, 1996 by and among R. M. Pearce and 
           Coho Energy, Inc.

*10.13     First Amendment to Employment Agreement 
           dated as of August 19, 1996 by and among 
           Eddie M. LeBlanc, III and Coho Energy, Inc.

 11.1      Statement ReComputation Earnings Per Share

 21.1      Coho Energy, Inc. List of Subsidiaries
           
 23.1      Independent Auditors Consent

 23.2      Consent of Independent Public Accountants

 27        Financial Data Schedule
</TABLE>