<PAGE>   1
                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549

                                   FORM 10-K

(Mark One)

[X]               ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                        SECURITIES EXCHANGE ACT OF 1934
                  For the fiscal year ended December 31, 1998
                                            -----------------
                                       OR

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

               For the transition period from _______ to ________.

                         Commission file number 0-22576

                               COHO ENERGY, INC.
             (Exact name of registrant as specified in its charter)
 
           Texas                                        75-2488635       
-------------------------------                   ---------------------
(State or other jurisdiction of                       (IRS Employer
incorporation or organization)                    Identification Number)

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

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

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

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

         Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding twelve months (or for such shorter period that
the registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes  [X]    No   [ ]   

         Indicate by check mark 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 March 5, 1999, 25,603,512 shares of the registrant's Common
Stock were outstanding and the aggregate market value of all voting stock held
by non-affiliates was $14 million based upon the closing price on the Nasdaq
Stock Market 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 in 1999 which
Proxy Statement is expected to be filed within 120 days of the end of the
Registrant's fiscal year.

<PAGE>   2
                               TABLE OF CONTENTS
<TABLE>
<CAPTION>


                                                                                                      PAGE
                                     PART I                                                           ----
<S>                                                                                                   <C> 
         Item 1.  Business .............................................................................  3
         Item 2.  Properties ........................................................................... 19
         Item 3.  Legal Proceedings .................................................................... 19
         Item 4.  Submission of Matters to a Vote of Security Holders .................................. 19

                                    PART II

         Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters ................ 21
         Item 6.  Selected Financial Data .............................................................. 22
         Item 7.  Management's Discussion and Analysis of Financial Condition and  
                      Results of Operations ............................................................ 23
         Item 7A. Quantitative and Qualitative Disclosure about Market Risk ............................ 32
         Item 8.  Consolidated Financial Statements .................................................... 34
         Item 9.  Changes in and Disagreements with Accountants on Accounting and  
                      Financial Disclosure ............................................................. 57

                                    PART III

         Item 10. Directors and Executive Officers of the Registrant ................................... 57
         Item 11. Executive Compensation ............................................................... 57
         Item 12. Security Ownership and Certain Beneficial Owners and Management ...................... 57
         Item 13. Certain Relationships and Related Transactions ....................................... 57

                                    PART IV

         Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ...................... 58
</TABLE>


FORWARD-LOOKING STATEMENTS

         This Form 10-K includes certain statements that may be deemed to be
"forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of
the Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included in this Form 10-K that address
activities, events or developments that the Company expects, projects, believes
or anticipates will or may occur in the future, including such matters as crude
oil and natural gas reserves, future acquisitions, future drilling and
operations, future capital expenditures, future production of crude oil and
natural gas and future net cash flow are forward-looking statements. These
statements are based on certain assumptions and analyses made by management of
the Company in light of its experience and its perception of historical trends,
current conditions, expected future developments and other factors it believes
are appropriate in the circumstances. Such statements are subject to a number
of assumptions, risks and uncertainties, including those related to
competition, general economic and business conditions, prices of crude oil and
natural gas, the business opportunities (or lack thereof) that may be presented
to and pursued by the Company, changes in laws or regulations and other
factors, many of which are beyond the control of the Company. Such statements
are not guarantees of future performance and actual results or developments may
differ materially from those projected in the forward-looking statements.

DEFINITIONS

         See Page 6 for a list of definitions of certain technical terms used
herein.


                                       2
<PAGE>   3
PART I

ITEM 1.  BUSINESS AND PROPERTIES

GENERAL

         Coho Energy, Inc. ("Coho" or the "Company") is an independent energy
company engaged, through its wholly owned subsidiaries, in the development and
production of, and exploration for, crude oil and natural gas. The Company's
crude oil activities are concentrated principally in Mississippi and Oklahoma,
where, to the Company's knowledge, it is each state's largest producer of crude
oil. At December 31, 1998, the Company's total proved reserves were 111.1 MMBOE
with a Present Value of Proved Reserves of $269.3 million, approximately 67.4%
of which were proved developed reserves. At December 31, 1998, approximately
90% of the Company's total proved reserves were comprised of crude oil. At
December 31, 1998, the Company's operations were conducted in 21 major
producing fields, 17 of which were operated by the Company. The average working
interest of the Company in the fields it operates was approximately 76% .

         The Company commenced operations in Mississippi in the early 1980s and
has focused most of its development efforts in that area. The Company believes
that the salt basin in central Mississippi offers significant long-term
potential due to the basin's large number of mature fields with multiple
hydrocarbon bearing horizons. The application of proven technology to these
underexploited and underexplored fields yields attractive, lower-risk
exploitation and exploration opportunities. As a result of the attractive
geology and the Company's experience in exploiting fields in the area, the
Company has accumulated a large inventory of potential development drilling,
secondary recovery and exploration projects in this basin.

         In December 1997, the Company acquired interests in 14 principal
producing fields located primarily in southern Oklahoma. These properties are
very similar to the Company's Mississippi properties. The Company believes that
its concentration in the onshore Gulf Coast and Mid-Continent regions provides
it with important competitive advantages such as its extensive databases,
operational infrastructure and economies of scale.

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

         The Company's focus in the onshore Gulf Coast and Mid-Continent
regions has resulted in significant production, reserve and EBITDA growth. The
Company's average net daily production has increased in each of the last five
years from 5,203 BOE in 1993 to 17,599 BOE in 1998, representing a compound
annual growth rate of 27.6%. Over the five-year period ended December 31, 1998,
the Company discovered or acquired approximately 103.4 MMBOE of proved reserves
at an average finding cost of $4.87 per BOE. Over the same period, the Company
has replaced over 529% of its production. This increase in reserves from 27.2
MMBOE at year end 1993 to 111.1 MMBOE at year end 1998 represents a five-year
compound annual growth rate of 32.5%. Concurrent with the increase in
production, EBITDA has increased from $16.5 million in 1993 to $32.1 million in
1998.

         In August 1998, the Company announced that it had reached an agreement
to issue $250 million of common stock at $6.00 per share (approximately 41.7
million shares) to HM4 Coho L.P. ("HM4"), a limited partnership managed by
Hicks, Muse, Tate & Furst Incorporated, giving HM4 ownership interest in the
Company of approximately 62%. On December 15, 1998, the Company announced that
HM4 was terminating the prior agreement and that the Company was considering a
restructuring of the HM4 agreement, which had received shareholder approval, to
reflect an increase in the number of shares that the Company would issue for the
$250 million purchase price based on a price per share of $4.00 versus $6.00.
After working through all of the issues and reaching a verbal agreement with all
of the interested parties with regard to the proposed restructuring, the Company
was informed by HM4 on February 12, 1999 that it was no longer interested in the
investment.

FUTURE OPERATIONS

         On February 22, 1999, the Company was informed by the lenders under
the Company's existing credit facility that its borrowing capacity under such
facility at January 31, 1999 had been reduced from $242 million to $150 million
as a result of the deterioration in the valuation of the collateral of crude
oil and natural gas reserves, primarily due to crude oil and natural gas price
declines. The Company's over advance position was $89.6 million based on the
reduced 
 

                                      3

<PAGE>   4

borrowing capacity and, pursuant to the credit facility, such amount is due in
five equal monthly installments beginning March 2, 1999. The Company was unable
to cure the over advance by the March 2, 1999 deadline as required by the
credit facility. On March 8, 1999, the Company received written notice from the
lenders that it was in default under the credit facility and the lenders
reserved all rights, remedies and privileges as a result of the payment default.
Additionally, the Company's $150 million of 8 7/8% Senior Subordinated Notes
("Senior Notes") include certain cross default provisions which may result in a
default under the terms of the related indenture. Although the lenders under the
existing bank credit facility have not accelerated the full amount outstanding
of $235 million as of December 31, 1998 and although the Company may not be in
technical default under the Senior Notes indenture, all amounts outstanding
under these facilities as of December 31, 1998 have been classified as current
maturities because the Company is currently unable to cure the existing or
pending defaults within the required terms of the related facility or indenture.

         The Company is exploring its alternatives to resolve its current
liquidity problems, including (a) the current default under the existing bank
credit facility, (b) the potential acceleration of all amounts due under its
existing bank credit facility and the Senior Notes, and (c) inadequate cash
flow from operations to support upcoming interest payments due on the credit
facility on April 6, 1999 and on the Senior Notes due on April 15, 1999 or to
meet other accrued liabilities as they become due. The alternatives available
to the Company include, but are not limited to, the conversion of a portion or
all of the Senior Notes to equity, raising additional equity and/or refinancing
the Company's existing bank credit facility to make overdue principal and
interest payments on its indebtedness and to provide additional capital to fund
well repairs on and the continued development of the Company's properties. The
Company is also evaluating cost reduction programs to enhance cash flow from
operations. There can be no assurance that the Company will be successful in
resolving its liquidity problems through the alternatives set forth above and
may seek protection under Chapter 11 of the United States Bankruptcy Code while
pursuing its other financing and/or reorganization alternatives. These factors,
among others, raise substantial doubt concerning the ability of the Company to
continue as a going concern.

BUSINESS STRATEGY

         While the Company remains committed in the long term to its
multifaceted growth strategy of the past, as discussed below, current low oil
prices and resulting cash flow dictates the Company's near-term business
strategy is to further reduce operating costs and to direct all capital
expenditures to low-risk projects which result in immediate and maximum cash
flows. Most of the near-term capital expenditures are expected to be spent in
Oklahoma. The Company's Oklahoma properties offer numerous shallow oil and gas
recompletion and drilling opportunities with favorable economics even in
today's price environment.

         In the past the Company has pursued a multifaceted growth strategy, as
follows:

         Relatively Low-Risk Field Development. The Company maximizes
production and increases 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. Since 1994, the Company has drilled
92 development wells, of which 88% were completed successfully.

         Use of Technology. The Company identifies exploration prospects and
develops reserves in the vicinity of its existing fields using technologies
that include 3-D seismic technology. The Company first began using 3-D seismic
technology in the Laurel field in Mississippi in 1983, and has recently shot
two large 3-D seismic programs in and around its existing properties in
Mississippi. At the time of purchase, the Company acquired four 3-D seismic
programs in and around its Oklahoma properties. These programs have produced an
attractive inventory of exploration projects that can be pursued in the future.

         Acquire Properties with Underdeveloped Reserves. The Company acquires
underdeveloped crude oil and natural gas properties which have geological
complexity and multiple producing horizons. Management believes that the
Company's extensive experience in Mississippi developed over the past 15 years
should enable it to efficiently increase reserves and improve production rates
in similar geologically complex environments. Additionally, management believes
that this experience gives the Company a competitive advantage in evaluating
similarly situated acquisition prospects. See "Oil and Gas Operations -
Principal Areas of Activity - Mid-Continent Area".


                                       4
<PAGE>   5

         Significant Control of Operations. The Company's long-term strategy of
increasing production and reserves through acquiring and developing
multiple-zone fields requires the Company to develop a thorough understanding
of the complex geological structures and maintain operational control of field
development. Therefore, the Company strives to operate and obtain high working
interests in all its properties. As of December 31, 1998, the Company operated
17 of the 21 major fields in which it has production. Of the operated
properties, the Company's average working interest is approximately 76%.
Operating control, combined with the Company's significant technical and
geological expertise, enables the Company to control the magnitude and timing
of capital expenditures and field development.

         Geographic Focus. The Company has been able to maintain a low cost
structure through asset concentration. At December 31, 1998, approximately 89%
of the Company's Gulf Coast reserves were concentrated in five fields, and 84%
of the Company's Mid-Continent reserves were concentrated in six fields. Asset
concentration permits operating economies of scale and leverages operational,
technical and marketing capabilities. As a result, the Company has been able to
achieve favorable average production costs of $4.18 per BOE for 1998.

         OTHER ACTIVITIES. On December 2, 1998, the Company sold its natural
gas assets located in Monroe, Louisiana, to an unrelated third party for a net
sales price of $61.5 million. These assets represented approximately 14% of the
Company's year end 1997 proved reserves and included two gas gathering systems.

         Effective December 31, 1997, the Company acquired approximately 50
MMBbls of crude oil and natural gas liquid reserves and approximately 33 Bcf of
natural gas reserves as well as interests in more than 25,000 gross acres
concentrated primarily in southern Oklahoma, including 14 principal producing
fields, from Amoco Production Company. Daily net production from the properties
during December 1997 was approximately 7,300 BOE. Consideration paid by the
Company for the acquisition of these properties was $257.5 million cash and
warrants to purchase one million common shares of the Company at $10.425 per
share for a period of five years.

         On April 3, 1996, Interstate Natural Gas Company ("ING"), a wholly
owned subsidiary of the Company, 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.
Accordingly, the marketing and transportation segment is accounted for as
discontinued operations herein.

         THE COMPANY. 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"). References herein to "Coho" or the
"Company", except as otherwise indicated, refer to Coho Energy, Inc. and its
subsidiaries. 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.


                                       5
<PAGE>   6

DEFINITIONS

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

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

         "Bcf" means billions of cubic feet.

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

         "BOPD" means Bbls per day.

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

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

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

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

         "MBbls" means thousands of Bbls.

         "MBOE" means thousands of BOE.

         "Mcf" means thousands of cubic feet.

         "MMBbls" means millions of Bbls.

         "MMBOE" means millions of BOE.

         "MMbtu" means millions of British Thermal Units.

         "MMcf" means millions of cubic feet.

         "Net" is determined by multiplying gross wells or acres by 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.

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

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


                                       6
<PAGE>   7

                            OIL AND GAS OPERATIONS

         Coho has focused its operations on three main activities: conventional
exploitation, secondary recovery and exploration. Each of these interrelated
activities plays an important role in the Company's continuing production and
reserve growth. The Company's 1998 operations have been conducted primarily in
the Brookhaven, Laurel, Martinville, Soso and Summerland fields in Mississippi,
and the Bumpass, Sholem Alechem and East Fitts Units in Oklahoma.

         Conventional Exploitation. The Company's properties are characterized
by the large number of formations that have been productive, as well as by the
large number of wells that have been drilled over the past 50 years. These well
histories provide considerable geological and reservoir information for use in
further exploration and exploitation. In 1998, Coho spent approximately $48
million of its total capital expenditures of $70 million on exploitation
projects.
         Acquisition of mature underdeveloped and underexplored fields has been
one of the key elements to the Company's strategy of building reserves and
creating shareholder value. By capitalizing on its operating knowledge and
technical expertise, the Company has been able to acquire properties and
develop substantial additional low-cost reserves through conventional
development drilling and exploration opportunities. This strategy is
illustrated in the Company's 1995 acquisition of the Brookhaven field in
Mississippi. Since acquiring this property, the Company has increased total
daily field production as a result of successful exploitation and exploration
to approximately 1,123 net BOE at December 31, 1998, from approximately 230 net
BOE at the time of acquisition. In addition, the Company increased the proved
reserves associated with its Mid Continent properties to 73.8 MMBOE at December
31, 1998 from 55.5 MMBOE at the time of their acquisition in December 1997 due
to the Company's acquisition of additional working interest in the properties
and the successful exploitation of the Springer, Deese, Viola, Hunton and
Bromide reservoirs in 1998.

         Secondary Recovery. Over the last four years, the Company has
evaluated 20 secondary recovery projects in the Mississippi salt basin. Six of
these projects have been successfully developed and 14 are undergoing further
evaluation or are in the pilot phase. Since the acquisition of its Oklahoma
properties, the Company has identified 11 new secondary recovery projects to be
developed. These projects are currently in the study or planning phases.
Facilities and wellbores are being evaluated to begin pilot waterfloods in
three of these projects. The current waterflood operations have been an effort
by the Company to lower operating expenses and improve production enhancement
opportunities through low cost waterflood conformance work. In 1998, the
Company spent approximately $14 million of its total capital expenditure budget
on secondary recovery projects. These projects have demonstrated strong
production response and meaningful reserve additions. In addition, these
projects incur low production costs due to existing field infrastructures and
the ability to reinject produced water from current operations. The Company
believes opportunities exist for adding secondary recovery projects throughout
the Company's current field inventory.

         Exploration. Because of the many productive formations located within
the Company's producing properties, dry hole risks are substantially reduced,
improving exploration economics. The Company has drilled several successful
exploration wells in the currently defined Brookhaven, Laurel, Martinville and
Eola fields. In 1995, the Company completed a 24-square mile 3-D seismic survey
on the Martinville field. Based on this data, two successful exploratory wells
were completed, one in 1996 and one in 1997. The Company has identified
additional opportunities in the Martinville field; however, lower oil prices
and budget constraints did not allow the Company to pursue these opportunities
in 1998. If oil prices improve to more acceptable levels, the Company may
pursue these drilling opportunities. In 1996, the Company completed a 37-square
mile 3-D seismic survey encompassing the Laurel field, the Company's largest
crude oil producing field, which currently has producing properties covering
less than one square mile within the survey area. Based on initial
interpretations, several exploration wells are planned in the future, and a
"look-alike" prospect west of the Laurel field has been identified. The Company
believes each of these fields has significant exploration reserve potential
relative to the Company's reserve base.

         Along with the producing properties acquired in Oklahoma in 1997, the
Company acquired approximately 95 square miles of 3-D and 2,750 miles of 2-D
seismic data. A large portion of the 3-D data is over areas of future reserve
potential. The 3-D data will be useful in enhancing waterflood development and
exploration of the deeper objectives.


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<PAGE>   8

Principal Areas of Activity

         The following table sets forth, for Coho's major producing areas,
average net daily production of crude oil and natural gas on a BOE basis for
each of the years in the three-year period ended December 31, 1998, and the
number of productive wells producing at December 31, 1998:

<TABLE>
<CAPTION>
                               Year Ended December 31,                        At December 31, 1998
                            -----------------------------          -----------------------------------------
                                                                        Net
                            1996        1997         1998            Productive                     
                            ----        ----         ----               Wells                        Average
       Field                BOE/        BOE/         BOE/          --------------     Percentage     Working
                            day         day          day           Oil        Gas      Operated     Interest
                            ---         ---          ---           ---        ---      --------     --------
<S>                        <C>         <C>          <C>            <C>       <C>       <C>          <C>
Mississippi ........       6,861       8,178        8,202          127           3       96%          90%
Oklahoma (a) .......          --          --        6,345          634          36       52%          42%
Louisiana (b) ......       2,892       2,848        2,409           --          --       --           --
Other ..............          16         201          643            2          --        8%          10%
                           -----       -----        -----          ---         ---       --
          Total ....       9,769      11,227       17,599          763          39
                           =====      ======       ======          ===         ===
</TABLE>
------------
(a) These properties were acquired effective December 31, 1997. No production
    was recorded in 1997. 

(b) These properties were sold December 2, 1998.

GULF COAST AREA

         Brookhaven Field, Mississippi. In 1995, the Company purchased a 93%
working interest in the unitized Brookhaven field covering more than 13,000
acres. At the time of acquisition, there were 11 active wells and 159 inactive
wells. Proved reserves were 1.2 MMBOE and net production averaged approximately
230 BOE per day, producing only from the Tuscaloosa formation at 10,500 feet.

         Like other fields, Coho made the acquisition anticipating additional
field-wide recoveries through development drilling, recompletions, secondary
recovery and exploration. During its first year of ownership, the Company
focused its efforts on expanding its understanding of the Tuscaloosa reservoir.
Company mapping suggested less than 25% of the oil in place from the Tuscaloosa
reservoir had been recovered. As a result of its study, the Company identified
and has drilled six new Tuscaloosa well bores in the field to date. The six
penetrations found unswept crude oil reserves associated with structural and
stratigraphic complexity. Four of these penetrations have been completed as
commercial producers and two wells will be used as injectors to aid the
secondary recovery operations. In 1998, the Company continued its detailed
study and mapping of the stratigraphically complex Tuscaloosa reservoirs and
initiated several waterflood pilot areas.

         In addition to its exploitation success, the Company has had
significant exploration success. In 1997 and early 1998, the Company
experienced successful deep exploratory results in the Washita Fredricksburg,
Paluxy and Rodessa formations, with initial production from these horizons in
excess of 1,600 gross BOE per day. Due to deep structural complexity realized
with the 1997 and early 1998 drilling, additional drilling was halted until new
seismic data was acquired. In 1998, 35 miles of 2-D seismic data was acquired
and interpreted. This 2-D seismic data has improved the structural definition
of the deep drilling potential in these formations.

         Production in Brookhaven in 1998 averaged 1,123 BOE per day and proved
reserves at December 31, 1998 were 7.2 MMBOE, a 28.3% increase over 1997 proved 
reserves.

         Cranfield Field, Mississippi. As a result of the exploration success
at Brookhaven, the Company leased approximately 7,900 net acres on a similar
geologic structure near the Brookhaven field in the Cranfield field. In 1998,
detailed mapping using subsurface data from existing well bores and existing
2-D seismic data was performed. Drilling prospects were generated at depths of
6,000 feet to 11,000 feet in four different horizons: the Wilcox, Eutaw,
Tuscaloosa and Washita Fredricksburg formations. Two existing wellbores were
reentered during the second half of 1998. The Hosston and Mooringsport
formations were tested unsuccessfully in one deep existing wellbore; however,
excellent reservoir quality rock was found in the Mooringsport formation, which
the Company believes remains a future exploitation opportunity. A re-entry of
an existing shallow wellbore proved successful in both the Washita
Fredricksburg and Wilcox formations. The Washita Fredricksburg formation tested
at a rate of 700 Mcf per day and 


                                       8
<PAGE>   9

is currently awaiting pipeline connection. While no production sales occurred
during 1998, the Company's successful testing and mapping resulted in 1.0 MMBOE
of proved reserves at December 31, 1998.

         Laurel Field, Mississippi. The Laurel field is a multi-pay geological
setting with producing horizons from the Eutaw formation (approximately 7,500
feet) to the Hosston formation (approximately 13,500 feet). It is the Company's
largest oil producing property and represented approximately 43% of Coho's
total Mississippi production on a BOE basis during 1998. At December 31, 1998,
the field contained 45 wells producing from the Stanley, Christmas, Tuscaloosa,
Washita Fredricksburg, Paluxy, Mooringsport, Rodessa, Sligo and Hosston
reservoirs. Proved reserves at Laurel totaled 9.4 MMBbls at December 31, 1998.

         The Company considers the Laurel field both an exploration and
exploitation success. In 1983, at the time of the initial acquisition, the only
then existing well in what is now the Laurel field had been operating for 24
years and was only producing 47 BOPD. Coho then proceeded to employ 3-D seismic
technology to assist in defining the multi-pay zones in the field and commenced
an extensive drilling program to increase primary production, utilizing a
combination of vertical, high-angle and horizontal drilling techniques.

         The Company has also implemented successful secondary recovery
programs in a number of Laurel's producing reservoirs. In recent years,
secondary recovery programs were started in the Mooringsport, Rodessa, Sligo
and Tuscaloosa Stringer reservoirs.
The production response from the secondary recovery projects has been strong.

         In addition to the continued exploitation program, the Company had
continued an active exploration program at Laurel. In 1996 and 1997, much of
the Company's focus at Laurel was directed toward a mineral leasing program,
permitting and surveying associated with shooting a 37-square mile 3-D seismic
program. In 1998, the Company evaluated the 3-D seismic data to better
understand the exploration potential within the Laurel field as it is currently
defined, as well as to define exploration possibilities in the acreage
surrounding the field.

         The average net daily production for 1998 from Laurel was 3.5 MBOE,
down from the level experienced in 1997 due to a scaled back operating and
capital program which resulted from the substantial decline in commodity prices
experienced in 1998. At December 31, 1998 proved reserves were 9.4 MMBOE, down
approximately 39% from year end 1997. The reserve decline was attributable
primarily to low year-end oil prices.

         Martinville Field, Mississippi. The Martinville field was originally
discovered in 1957 and was acquired by Coho in April 1989. At the time of
acquisition, Martinville was only producing 80 BOE per day, while the average
production in 1998 was 1.5 MBOE per day. The field covers more than 7,400
acres, and currently has 21 producing wells. Like Laurel, the field is
characterized by highly complex faulting and produces from multiple horizons.
Coho currently has an average working interest of 97% in the field.

         In late 1995, the Company conducted a 3-D seismic shoot over a
24-square mile area to enhance the Company's ability to exploit primary
reserves through continued reservoir delineation and to develop secondary
recovery projects in the Mooringsport, Rodessa and Sligo formations.

         Since 1996, the Company has successfully drilled wells to the Hosston,
Sligo, Rodessa, Mooringsport and Washita Fredricksburg formations, with two
successful development wells drilled and completed in 1998 in the Sligo and
Washita Fredricksburg reservoirs.

         With declining oil prices experienced in 1998, the Company spent much
of the year refining the 3-D seismic interpretation of Martinville. The Company
currently has defined six exploration prospects along with numerous development
drilling opportunities. Proved reserves at year end 1998 totaled 6.2 MMBOE, a
10% decline from year end 1997. Like Laurel this reserve decline was due to low
oil prices.

         Soso Field, Mississippi. In mid-1990, the Company acquired a 90%
working interest in the Soso field, which was originally discovered in 1945 and
covers approximately 6,461 acres. At the time of acquisition by the Company,
the field produced 225 BOPD. In 1998, the average daily production was 807 BOE,
a decrease of 33% from 1997 average daily production. Reserves at December 31,
1998 totaled 5.0 MMBOE, an 18% decrease from year end 1997. Production and
reserve decreases were attributable to low commodity prices throughout the year
and resulting minimal capital expenditures.


                                       9
<PAGE>   10

         Soso is a large, geologically complex field which had already produced
over 75 MMBOE at the time Coho acquired it. Also, like Brookhaven, Coho's
detailed mapping of the field suggested that less than 25% of the total crude
oil had been recovered. Soso was acquired by the Company primarily to increase
total recoverable reserves by another 5% to 15% through recompletions in
existing wellbores, development drilling and secondary recovery projects.

         Most of the Company's early production growth at Soso was associated
with workovers and recompletions on existing wells, with some development
drilling taking place; however, with the success of secondary recovery projects
at Laurel and Martinville, the Company took a fresh look at the field, and
since then secondary recovery projects have been initiated in the Cotton
Valley, Sligo and Rodessa formations. These projects have played a significant
role in the production and reserve growth experienced since 1990.

         The most significant expenditure at Soso during 1998 was the
acquisition of 35 miles of new 2-D seismic data. This 2-D seismic data should
enhance the Company's development of the Hosston and Cotton Valley formations.
Coho believes many more exploitation opportunities exist for primary as well as
secondary reserves in the multi-reservoir field.

         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. At December 31, 1998, the Company operated 21
producing wells and has an average working interest of 90% in this unitized
field.

         The Company assumed operating control of the Summerland field in
November 1989. Recompletions, development drilling and the installation of
higher volume artificial lift equipment increased net crude oil production from
415 BOE per day (of which only 200 BOE per day were economic) in 1989 at the
date of acquisition, to 1,019 BOE per day in 1998. Average daily production
during 1998 was down 9% from 1997 average daily production as a result of the
natural decline of the reservoirs and low capital expenditures during the year.

         At December 31, 1998, the Summerland field had proved reserves of 5.3
MMBOE. This represents a 25% decrease from year end 1997 and like Laurel,
Martinville and Soso the reserve decline is due primarily to low oil prices.

MID-CONTINENT AREA

          In December 1997, the Company acquired interests in more than 25,000
gross acres concentrated primarily in southern Oklahoma, including 14 principal
producing fields. Of the 14 major producing fields, the Company is operator of
eleven fields and at December 31, 1998 had an average working interest in the
fields it operates of approximately 73%.

         These properties are very similar to the Company's Mississippi salt
basin operations and the Company believes that the application of its
substantial knowledge base should benefit in the development of these
properties. In 1998, the Company began an exploration and exploitation program
which resulted in the drilling of 19 gross wells, 18 of which were completed
successfully. Additionally, the Company began interpreting 3-D seismic
information on two fields in 1998 and has identified several drilling
opportunities as a direct result of this seismic information. Capital
expenditures in the Mid-Continent area totaled approximately $18.5 million in
1998.

         Bumpass Unit, Oklahoma. The Bumpass Unit, located in Carter County,
Oklahoma, was discovered in 1924. Production is primarily from both structural
and stratigraphic traps within the Deese and Springer reservoirs. The Deese
reservoirs are typically encountered at depths between 3,500 and 4,500 feet
with the Springer reservoirs located from 4,500 to 6,700 feet.

         Currently, the Company's primary focus at Bumpass is to exploit the
Flattop and Goodwin sands located in the Springer formation, which it believes
to be underdeveloped. In 1998, the Company drilled one well, deepened another
and worked over a third well, increasing gas production 2,945 net Mcf per day.
The Company intends to continue this exploitation program in 1999.
Additionally, the Company is studying the Humphrey sands, which are in the
upper portion of the Springer formation, to determine their waterflood
potential. The Company plans to initiate a waterflood program in 1999. At
December 31, 1998, the Company had an average working interest of approximately
65% in the Bumpass field.


                                      10
<PAGE>   11
         Average net daily production in 1998 was 623 BOE. Proved reserves at
December 31, 1998 totaled 5.0 MMBOE, an increase of 42% over the 3.5 MMBOE at
the end of 1997. This increase is a direct result of the Company's success in
exploiting the Springer formation in 1998.

         Sholem Alechem Fault Block "A" Unit, Oklahoma. Located in Stephens
County, Oklahoma, the Sholem Alechem Fault Block "A" Unit ("SAFBAU") was
discovered in 1947. As with the Bumpass Unit, production at SAFBAU originates
primarily from the Deese and Springer reservoirs.

         In 1998, the Company deepened four wells into the Flattop and Goodwin
sands located in the Springer formation, all of which were successful. Initial
production from these wells totaled over 500 BOE per day. Exploitation of the
Springer formation will continue into 1999. At December 31, 1998, the Company
had an average working interest in Sholem Alechem of approximately 86%.

         Net production in 1998 totaled 308 MBOE, or about 843 BOE per day.
Proved reserves at December 31, 1998 totaled 7.0 MMBOE, a 74% increase over
year end 1997. This increase is a direct result of the Company's acquisition of
additional working interests and success in exploiting the Springer formation
in 1998.

         East Fitts Unit, Oklahoma, The East Fitts Unit ("East Fitts") was
discovered in 1933, with production originating from the Cromwell, Hunton and
Viola reservoirs, depths ranging from 2,400 to 5,000 feet.

         The Company's current emphasis at East Fitts is to take the Viola
reservoir from ten acre spacing to five acre spacing. The Company believes that
this development will not only increase existing production but prove up
additional reserves. In 1998, the Company drilled five wells to the Viola
reservoir, all of which were successful, increasing production by 200 BOE per
day and adding approximately 600 MBOE in reserves. Additional wells to the
Viola reservoir are planned in 1999, depending on oil prices, and the Company
is planning to initiate pilot waterflood projects in the Chimney Hill
formation, a lower member of the Hunton reservoir, and the Bromide formation.
At December 31, 1998, the Company's average working interest in East Fitts was
approximately 83%.

         Average net daily production in 1998 was 1.2 MBOE. Proved reserves at
December 31, 1998 totaled 24.6 MMBOE, an increase of 51% over year end 1997.
This increase is a direct result of the Company's acquisition of additional
working interests and success in exploiting the Viola, Hunton and Bromide
reservoirs in 1998.

         Other Oklahoma. The Company operates eight other fields in Oklahoma -
East Velma Middle Block, North Alma Deese, Tatums, Jennings Deese, Graham
Deese, Eola S.E., Eola N.W. and Cox Penn. Total average net daily production in
1998 from these fields was 2.6 MBOE. East Velma Middle Block has significant
upside potential through secondary recovery. Like reservoirs have been
successfully waterflooded along the Velma complex. East Velma Middle Block is
the remaining block along this complex which has not been enhanced through
secondary recovery. Tatums is a shallow Deese producing unit which has been
evaluated to have significant upside potential through down spacing. Currently
the unit is developed on a ten acre spacing with some areas of the field
underexploited. A five acre drilling program and adjustments to current
waterflood injection could provide substantial upside potential. At year end,
net proved reserves from these properties totaled 33.8 MMBOE, an increase of
11% from year end 1997.

         The Company also has non-operating working interest in three fields in
Oklahoma. In 1998, total average net daily production was 1,479 BOE and year
end reserves were estimated at 3.5 MMBOE.

         Since the acquisition of the Oklahoma Properties, the Company has
identified 11 new secondary recovery projects to be developed. These projects
are currently in the study or planning phases. Facilities and wellbores are
being evaluated to begin pilot waterfloods. The current waterflood operations
have been an effort by the Company to lower operating expenses and improve
production enhancement opportunities through low cost waterflood conformance
work. These projects have demonstrated strong production response. In addition,
these projects incur low production costs due to existing field infrastructures
and the ability to reinject produced water from current operations. The Company
believes opportunities exist for adding secondary recovery projects throughout
the Company's current field inventory. Additionally, the Company believes that
substantial Springer through Simpson gas potential exist in and around Coho's
currently operated properties. This potential will be a focal point of low risk
exploration through deepening of existing wellbores or recompletions which
require less capital as compared to drilling for these objectives. Historically
in these areas, gas has not been the primary focus of exploitation and
technology has now allowed commercial develoment of these deeper, tighter
objectives.


                                      11
<PAGE>   12

OTHER DOMESTIC PROPERTIES

         The Company also has working interests in other producing properties
in Mississippi and Texas. The Company operates the Bentonia and Frio properties
in Mississippi and owns non-operated working interests in the Glazier property
in Mississippi, the Clarksville field in Texas and a field in state waters
offshore North Padre Island, Texas. As of December 31, 1998, these fields had
combined net proved reserves of 3.2 MMBOE.

TUNISIA, NORTH AFRICA

         The Company has a 45.8% interest in a permit covering 1.4 million gross
acres in Tunisia, North Africa that it acquired from its former Canadian parent
company. During 1994, the Company and its joint interest partners conducted a
seismic survey on the Anaguid permit in Tunisia. In October 1995, the Company
and its partners drilled an unsuccessful, exploratory well on its Anaguid permit
in southern Tunisia. In early 1997, the Company and its partners conducted a 465
kilometer 2-D seismic program in a new area of the Anaguid permit. The Company
is in the process of finalizing the location for the next exploratory well which
must be drilled by June 1999 or the acreage concession will expire. The
Company's estimated net cost to drill this well is approximately $2.5 million
and the Company's net carrying cost for its investment in the Anaguid permit is
approximately $5.7 million as of December 31, 1998. If the Company is unable to
drill this well by June 1999 and the acreage concession expires, the Company
will incur a liability of approximately $4.0 million for unfulfilled
commitments, of which $3.7 million is due to the Tunisian government. Although
the Company intends to drill this well,  the Company cannot currently predict
whether it will have the financial resources to make these expenditures.

Production

         The following table sets forth certain information regarding the
Company's production volumes, average prices received and average production
costs associated with its sales of crude oil and natural gas for each of the
years in the three-year period ended December 31, 1998:

<TABLE>
<CAPTION>
                                                                  Year Ended December 31,
                                                        ---------------------------------------
                                                         1996            1997             1998
                                                        ------          ------           ------
<S>                                                 <C>              <C>               <C>
CRUDE OIL:
   Volumes (MBbls) ..........................            2,468            2,820            5,069
   Average sales price (per Bbl)(a) .........        $   16.42        $   16.31        $   10.40

NATURAL GAS:
   Volumes (MMcf) ...........................            6,646            7,666            8,125
   Average sales price (per Mcf)(b) .........        $    2.07        $    2.23        $    1.98

AVERAGE PRODUCTION COST (PER BOE)(c) ........        $    3.88        $    3.90        $    4.18
</TABLE>

------------------
(a)      Includes the effects of crude oil price hedging contracts. Price per
         Bbl before the effect of hedging was $18.34, $16.42 and $10.40 for the
         years ended December 31, 1996, 1997 and 1998, respectively.

(b)      Includes the effects of natural gas price hedging contracts. Price per
         Mcf before the effect of hedging was $2.24, $2.22 and $1.92 for the
         years ended December 31, 1996, 1997 and 1998, respectively.

(c)      Includes lease operating expenses and production taxes.


                                      12
<PAGE>   13

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.

<TABLE>
<CAPTION>
                                                                     Year Ended December 31,
                                                       ---------------------------------------------------
                                                            1996               1997                1998
                                                           ------             ------              ------
                                                       Gross    Net      Gross      Net      Gross     Net
                                                       -----    ---      -----      ---      -----     ---
<S>                                                    <C>     <C>       <C>       <C>       <C>       <C>
EXPLORATORY:
   Crude oil                                             1      1.0         3       2.8         1       1.0
   Natural gas                                          --       --         1        .8        --        --
   Dry holes                                             1      1.0         1       1.0         2       2.0

DEVELOPMENT:
   Crude oil                                            13     12.0        10       9.3        26      21.7
   Natural gas                                           6      6.0        11       9.8         8       6.5
   Dry holes                                             4      3.7         2       2.0         5       4.9
   Service wells                                         8      7.5        --        --         2       1.0
                                                       ---     ----       ---      ----       ---      ----
Total                                                   33     31.2        28      25.7        44      37.1
                                                       ===     ====       ===      ====       ===      ====
</TABLE>
-------------
         At December 31, 1998, the Company was participating in 1 gross well
(.1 net) that was in completion stage.

Reserves

         The following table summarizes the Company's net proved crude oil and
natural gas reserves as of December 31, 1998, which have been reviewed by Ryder
Scott Company with regard to the Company's Mississippi properties and Sproule
Associates, Inc. with regard to the Company's Oklahoma properties. The other
properties in the table are related to the Company's crude oil and natural gas
reserves located in Texas which have been audited, depending on location, by
the above mentioned independent engineers.

<TABLE>
<CAPTION>
                                       Crude         Natural      Net Proved
                                        Oil            Gas         Reserves
                                      (MBbls)        (MMcf)         (MBOE)
                                      ------         -------      ----------
<S>                                   <C>            <C>          <C>   
Mississippi ..................         34,505          2,980         35,002
Oklahoma .....................         63,827         50,674         72,272
Other ........................          1,672         12,674          3,785
                                      -------        -------        -------
Total ........................        100,004         66,328        111,059
                                      =======        =======        =======
</TABLE>

         At December 31, 1998, the Company had net proved developed reserves of
74,898 MBOE and net proved undeveloped reserves of 36,161 MBOE. The Present
Value of Proved Reserves was $269.3 million, which represented $193 million for
the proved developed and $76 million for the proved undeveloped reserves. At
December 31, 1997, the Company reported total proved reserves of 119,668 MBOE
and the Present Value of Proved Reserves was $526.3 million. When excluding
1998 production and the reserves associated with the Company's Monroe field,
which was sold in 1998, the Company increased reserves 13,514 MBOE in 1998 over
1997 or 13.9%.

         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 volumes of production from crude oil and natural gas
properties decline 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.


                                      13
<PAGE>   14

         For further information on reserves, costs relating to crude oil and
natural gas activities and results in operations from producing activities, see
"Supplementary Information Related to Oil and Gas Activities" appearing in note
14 to the Consolidated Financial Statements of the Company included elsewhere
herein.

Acreage

         The following table summarizes the developed and undeveloped acreage
owned or leased by Coho at December 31, 1998:

<TABLE>
<CAPTION>
                                                            Developed                    Undeveloped
                                                      -------------------            --------------------
                                                       Gross          Net            Gross            Net
                                                       -----          ---            -----            ---
<S>                                                   <C>            <C>            <C>             <C>   
   Mississippi ....................................   25,086         23,722         28,246          23,718
   Oklahoma .......................................   38,463         28,376             40              40
   Texas ..........................................    4,276          3,435          1,380           1,380
   Offshore Gulf of Mexico ........................    5,760          2,269            ---             ---
                                                       -----          -----         ------          ------
Total                                                 73,585         57,802         29,666          25,138
                                                      ======         ======         ======          ======
</TABLE>

         At December 31, 1998, the Company also held a 45.8% working interest
in an exploratory permit in Tunisia, North Africa, covering 1,412,000 gross
acres.

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 crude oil and
natural gas leases at the time they are acquired by Coho. However, before the
Company acquires developed crude oil and natural 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
possible. 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 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 crude oil and natural gas properties, some of
which are subject to immaterial encumbrances, easements and restrictions. The
crude oil and natural 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.

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 desirable crude oil
and natural gas properties suitable for drilling, for materials and third-party
services essential for their exploration and development and for attracting and
retaining quality personnel. 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 and 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.


                                      14
<PAGE>   15

CUSTOMERS AND MARKETS

         Substantially all of Coho's crude oil is sold at the wellhead at posted
prices, as is customary 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 1998, three purchasers of the Company's crude oil and
natural gas, EOTT Energy Corp. ("EOTT"), Amoco Production Company and Mid
Louisiana Marketing Company, accounted for 42%, 28% and 14%, respectively, of
Coho's revenues. The Company has a three-year crude oil purchase agreement with
EOTT which was effective March 1, 1996. Under the crude oil purchase agreement,
the Company committed the majority of its crude oil production in Mississippi to
EOTT for a period of three years on a pricing basis of posting plus a premium.
This contract is currently being renegotiated. The Company has entered into a
contract with EOTT for approximately 50% of its heavy Mississippi crude oil with
a well head price of $8.50 per barrel.

         The majority of crude oil production in Oklahoma is sold to Amoco
Production Company on a pricing basis of posting plus a premium. Beginning
January 1, 1999 and for a nine-year period thereafter, Amoco has a right of
first refusal to match, in all respects, a competitive bid. The crude contract
was a component of the original Amoco purchase and sale agreement and provides
for a competitive annual review of the pricing mechanism.

         The price received by the Company for crude oil and natural gas may
vary significantly during certain times of the year due to the volatility of
the crude oil and natural gas market, particularly during the cold winter and
hot summer months. As a result, the Company periodically enters into forward
sale agreements or other 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 -- General" and Note
1 to the Consolidated Financial Statements of the Company included elsewhere
herein.

OFFICE AND FIELD FACILITIES

         The Company currently leases its executive and administrative offices
in Dallas, Texas, consisting of 47,942 square feet, under a lease that
continues through October 2000. The Company also leases field offices in
Laurel, Mississippi, covering approximately 5,000 square feet under a
non-cancelable lease extending through June 2000, and Ratliff City, Oklahoma,
covering approximately 10,000 square feet through January 2003.

GOVERNMENTAL REGULATION

         Regulation of Crude Oil and Natural Gas Exploration and Production.
Crude oil and natural 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, Oklahoma 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
crude oil and natural 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 natural 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 7% in Oklahoma. In addition, the Company has been active in
the adoption of legislation dealing with production and severance tax relief in
Mississippi, specifically where severance tax is either waived for a fixed
period of time, as in renewed production from inactive wells, or reduced to 50%
of regular rates for enhanced recovery projects. The state of Oklahoma has
adopted severance tax relief, where tax rates for posted crude oil priced less
than $14.00 per barrel would be 1%, between $14.00 and $17.00 per barrel would
be 4%, with a regular tax rate of 7% for prices over $17.00 per barrel.


                                      15
<PAGE>   16

         Legislation affecting the crude oil and natural 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 crude oil and natural gas industry
and its individual members, some of which carry substantial penalties for
failure to comply. The regulatory burden on the crude oil and natural gas
industry increases the Company's cost of doing business and, consequently,
affects its profitability.

         Offshore Leasing. Certain of the Company's operations are located on
federal crude oil and natural 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 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 or operators 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.

         Gas Royalty Valuation Regulations. In December 1997, the MMS published
a final rule amending its regulations governing valuation for royalty purposes
of gas produced from federal and Indian leases. The rule primarily addresses
allowances for transportation of gas and purports to clarify the methods by
which gas royalties and deductions for gas transportation are calculated. The
final rule became effective February 1, 1998. The rule purports to continue the
commitment of the MMS to assure that lessees deduct only the actual, reasonable
costs of transportation and not any costs of marketing. The rule identifies
certain specifically allowable and certain specifically nonallowable costs of
transportation.

         Crude 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 published a proposed rulemaking to
amend the current federal crude oil royalty valuation regulations. In July 1997,
the MMS published a supplementary proposed rulemaking concerning such
regulations. In February 1998, the MMS published another supplementary proposed
rulemaking. The intent of the rule is to decrease reliance on posted prices and
assign a value to crude oil that better reflects market value. In general, the
rule, as proposed, would base royalties on gross proceeds when the oil is sold
under an arm's length contract by either the producer or the producer's
marketing affiliate. Index pricing or other benchmarks would be used when oil is
not sold under an arm's length contract. On July 16, 1998, the MMS proposed
additional changes to its second supplementary proposed rule. On March 12, 1999,
the MMS published a notice reopening the public comment period on the second
supplementary proposed rule until April 12, 1999. In February 1998, the MMS also
published a notice of proposed rulemaking to amend the current regulations
establishing a value for royalty purposes of oil produced from Indian leases.
The proposed changes would decrease reliance on oil posted prices and use more
publicly available information for oil royalty calculation purposes under Indian
leases. The Company cannot predict what action the MMS will take on these
matters, nor can it predict at this stage of the rulemaking proceedings how the
Company might be affected by amendments to these regulations.

         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 crude oil pipeline rates. Effective as
of January 1, 1995, the FERC implemented regulations establishing an indexing
system for transportation rates for crude 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.


                                      16
<PAGE>   17

         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, crude oil and natural
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 Natural Gas
Act. 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 of sale of crude oil,
condensate or natural gas. It is impossible to predict the 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 crude oil spills and liability for damages resulting from such
spills into or upon navigable waters, adjoining shorelines or in the exclusive
economic zone of the United States. A "responsible party" includes the owner or
operator of an onshore facility or a vessel, or the lessee or permittee of the
area in which an offshore facility is located. The OPA requires the lessee or
permittee of the offshore area in which a covered offshore facility is located
to establish and maintain evidence of financial responsibility in the amount of
$35.0 million ($10.0 million if the offshore facility is located landward of the
seaward boundary of a state) to cover liabilities related to a crude oil spill
for which such person is statutorily responsible. The amount of required
financial responsibility may be increased above the minimum amounts to an amount
not exceeding $150.0 million depending on the risks posed by the quantity or
quality of crude oil that is handled by the facility. The MMS has promulgated
regulations that implement the financial responsibility requirements under the
OPA. The regulations use an offshore facility's worst case oil-spill discharge
volume to determine if the responsible party must demonstrate increased
financial responsibility. Because the Company's only offshore well is a natural
gas well that does not produce oil, as such term is defined in the MMS
regulations, the Company is not presently subject to the financial
responsibility requirements.

         The OPA subjects responsible parties to strict, joint and several and
potentially unlimited liability for removal costs and certain other damages
caused by an oil spill covered by the statute. It also imposes other
requirements on responsible parties, such as the preparation of a crude 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 Federal Water Pollution Control Act of 1972, as amended (the
"FWPCA"), imposes restrictions and strict controls regarding the discharge of
produced waters and other oil and gas wastes into navigable waters. These
controls have become more stringent over the years, and it is probable that
additional restrictions will be imposed in the future. Permits must be obtained
to discharge pollutants into state and federal waters. Certain state discharge
regulations and the Federal National Pollutant Discharge Elimination System
general permits prohibit the discharge of produced water and sand, drilling
fluids, drill cuttings and certain other substances related to the oil and gas
industry into coastal waters. The FWPCA provides for civil, criminal and
administrative penalties for any unauthorized discharges of oil and other


                                      17
<PAGE>   18

hazardous substances in reportable quantities and, along with the OPA, imposes
substantial potential liability for the costs of removal, remediation and
damages. State laws for the control of water pollution also provide varying
civil, criminal and administrative penalties and impose liabilities in the case
of a discharge of petroleum or its derivatives, or other hazardous substances,
into state waters.

         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 and for damages to natural resources. In
addition, 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.

         The Resource Conservation and Recovery Act ("RCRA") is the principal
federal statute governing the treatment, storage and disposal of hazardous
wastes. RCRA imposes stringent operating requirements (and liability for
failure to meet such requirements) on a person who is either a "generator" or
"transporter" of hazardous waste or an "owner" or "operator" of a hazardous
waste treatment, storage or disposal facility. At present, RCRA includes a
statutory exemption that allows most crude oil and natural gas exploration and
production wastes to be classified as non-hazardous waste. A similar exemption
is contained in many of the state counterparts to RCRA. At various times in the
past, proposals have been made to amend RCRA and various state statutes to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste under such statutes.
Repeal or modification of this exemption by administrative, legislative or
judicial process, or through changes in applicable state statutes, would
increase the volume of hazardous waste to be managed and disposed of by the
Company. Hazardous wastes are subject to more rigorous and costly disposal
requirements than are non-hazardous wastes. Any such change in the applicable
statutes may require the Company to make additional capital expenditures or
incur increased operating expenses.

         A sizable portion of the Company's operations in Mississippi is
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.
Inactive tanks are replaced, as necessary, with newer aboveground storage
tanks.

         Some states have enacted statutes governing the handling, treatment,
storage and disposal of naturally occurring radioactive material ("NORM"). NORM
is present in varying concentrations in subsurface and hydrocarbon reservoirs
around the world and may be concentrated in scale, film and sludge in equipment
that comes in contact with crude oil and natural gas production and processing
streams. Mississippi legislation prohibits the transfer of property for
residential or other unrestricted use if the property contains NORM above
prescribed levels. The Company is voluntarily remediating NORM concentrations
identified at several fields in Mississippi. In addition, the Company is a
defendant in several lawsuits brought in 1994 and 1996 by landowners alleging
personal injury and property damage from NORM at various wellsite locations.

         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 wildlife refugees in 1996. The Company sold its interest and natural gas
assets in the Monroe field on December 2, 1998. The purchaser agreed to assume
the Company's obligations under the remediation plan.

         Because the Company's strategy is to acquire interests in
underdeveloped crude oil and natural gas properties many of which have been
operated by others for many year, the Company may be liable for damage or
pollution caused by the former operators of such crude oil and natural gas
properties. The Company makes a provision for future site restoration charges on
a unit-of-production basis which is included in depletion and depreciation
expense. In addition, the Company may continue to be responsible for
environmental contamination on properties it transferred to others. The 


                                      18
<PAGE>   19

Company's operations are also subject to all the risks normally incident to the
operation and development of crude oil and natural gas properties and the
drilling of crude oil and natural 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 March 1, 1999, Coho had 144 employees associated with its
operations, including 26 field personnel in Mississippi and 28 field personnel
in Oklahoma. None of the Company's employees is represented by a union. The
Company considers its employee relations to be satisfactory.

ITEM 2.  PROPERTIES

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

ITEM 3.  LEGAL PROCEEDINGS

         The Company, together with several other companies, has been named as
a defendant in a number of lawsuits in which the plaintiffs claim purported
damages caused by naturally occurring radioactive materials at various wellsite
locations on land leased by the Company in Mississippi. All of the suits
purport to be based on similar factual allegations and seek damages primarily
for land damage, health hazard and mental and emotional distress. None of the
suits seek specific award amounts, but all seek punitive damages.

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

         In 1998, a suit was filed against the Company by the acquirer of the
Company's natural gas pipeline properties which were sold in 1996. This suit
alleges that the Company gave false and fraudulent information with regard to
the properties sold as well as alleging that the Company has interfered in
contracts and business relations subsequent to the sale. The plaintiff is
requesting payment for actual, punitive and other damages. The Company believes
these charges are without merit.

         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 aggregate, on the Company's financial position or results of
operations.

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

         A special meeting of shareholders was held on December 4, 1998 to vote
on an amendment to the Articles of Incorporation authorizing an increase in the
number of shares of the Company's Common Stock from 50 million to 100 million
and on the proposed sale of 41,666,666 shares of Common Stock to HM4 Coho L.P.
pursuant to a stock purchase agreement dated August 21, 1998, as amended.

         At the close of business on November 6, 1998, the record date for the
determination of stockholders entitled to vote at the meeting, there were
outstanding 25,603,512 shares of common stock, of which 16,326,427 were
represented at the meeting in person or by proxy. With regard to the amendment
to increase the number of authorized 


                                      19
<PAGE>   20

shares from 50 million to 100 million, 15,726,461 were voted in favor of the
proposal, 512,776 shares voted against the proposal and 87,190 shares abstained
from voting. There were no broker non-votes. With regard to the amendment to
approve the sale of 41,666,666 shares of common stock to HM4 Coho L.P.,
14,634,027 shares voted in favor, 473,056 shares voted against, 100,263
abstained from voting and there were 1,119,081 broker non-votes. Both issues
were approved by the voting shareholders.


                                       20
<PAGE>   21

                                    PART II

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

         The Company's Common Stock is listed on the Nasdaq Stock Market under
the symbol "COHO". 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>
1997
                  1st Quarter                                       $  9 1/4             $  6 7/8
                  2nd Quarter                                         11 1/2                6 7/8       
                  3rd Quarter                                         11 5/8                9         
                  4th Quarter                                         13                    8 1/4      
                                                                                 
1998
                  1st Quarter                                       $  9 5/8             $ 6  1/4     
                  2nd Quarter                                          9 1/4               6  1/4 
                  3rd Quarter                                          7 1/8               4  1/2 
                  4th Quarter                                          5 1/8               2 5/16 
                                                                                              
</TABLE>

         Prior to the opening of markets on Monday March 8, 1999, the Nasdaq
Stock Market halted trading on the Company's Common Stock based on Coho's
announcement that day of a receipt of a notice of default from the lenders under
the Company's Revolving Credit Facility. The Nasdaq Stock Market requested
additional information from the Company regarding the Company's compliance with
the continued listing requirements of the Nasdaq Stock Market. As of March 31,
1999, the Company is not able to respond because it has not formalized a
restructuring plan and trading on the Company's Common Stock on the Nasdaq Stock
Market has not resumed. On March 29, 1999, the Company received a letter from
the Nasdaq Stock Market that it has determined that the continued listing of the
Company's Common Stock on the Nasdaq Stock Market is no longer warranted. The
Company intends to request an oral hearing with the Nasdaq Stock Market, which,
pursuant to Nasdaq's Marketplace Rules, will stay any delisting action pending a
final decision by the Nasdaq Listing Qualifications Panel. The last reported
sale price of the Common Stock as reported on the Nasdaq Stock Market on March
5, 1999 was $5/8 per share. At March 22, 1999, there were 398 holders of record
of the Common Stock. The Company believes it has in excess of 12,000 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 and Senior Notes indenture restrict the payment of dividends by the
Company and CRI. Due to a current default under the Company's existing revolving
credit facility, and due to the Company's current and expected capital needs, it
is unlikely that the Company will pay dividends in the foreseeable future. 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 the subsidiaries of Coho Energy, Inc. Any
declaration of dividends by the subsidiaries of Coho Energy, Inc. would be
subject to Canadian or U.S. withholding tax at applicable tax rates.


                                       21
<PAGE>   22

ITEM 6.  SELECTED FINANCIAL DATA

       The following selected consolidated financial data for each of the five
years in the period ended December 31, 1998 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
"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>
                                                           1994(1)(2)      1995(2)          1996           1997            1998
                                                           ----------      -------          ----           ----            ----
                                                                         (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                                                      <C>             <C>             <C>            <C>             <C>
STATEMENT OF EARNINGS DATA:
     Operating revenues ...........................      $  26,464       $  40,903       $  54,272      $  63,130       $  68,759
     Operating costs ..............................          9,372          12,457          13,875         15,970          26,859
     General and administrative expenses ..........          3,435           5,400           7,264          7,163           7,750
     Allowance for bad debt .......................             --              --              --             --             894
     Depletion and depreciation ...................          9,989          14,717          16,280         19,214          28,135
     Writedown of crude oil and natural gas
           properties .............................             --              --              --             --         188,000
     Net interest expense .........................          3,972           8,048           7,464         10,474          32,721
     Other expense ................................            973              --              --             --           2,129
     Income tax expense (benefit) .................           (303)            112           3,483          4,020         (14,383)
     Earnings (loss) from continuing operations ...           (974)            169           5,906          6,288        (203,346)
     Net earnings (loss) ..........................         (1,654)          1,780           5,906          6,288        (203,346)
     Basic earnings (loss) from continuing
           operations per common share(3) .........      $   (0.07)      $   (0.02)      $    0.29      $    0.29       $   (7.94)
     Diluted earnings (loss) from continuing
           operations per common share(4) .........      $   (0.07)      $   (0.02)      $    0.29      $    0.28       $   (7.94)
     Basic earnings (loss) per common share(3) ....      $   (0.12)      $    0.05       $    0.29      $    0.29       $   (7.94)
     Diluted earnings (loss) per common share(4) ..      $   (0.12)      $    0.05       $    0.29      $    0.28       $   (7.94)

OTHER FINANCIAL DATA:
     Capital expenditures .........................      $  19,503       $  29,970       $  52,384      $  72,667       $  70,143

BALANCE SHEET DATA:
     Working capital (deficit)(5) .................      $  (2,379)      $  14,433       $   6,662      $  (2,021)      $(388,297)
     Net property and equipment ...................        171,524         175,899         210,212        531,409         324.574
     Total assets .................................        196,970         204,042         230,041        555,128         350,068
     Long-term debt, excluding current portion ....         86,311         107,403         122,777        369,924              -- 
     Redeemable preferred stock ...................         16,125              --              --             --              -- 
     Total shareholders' equity ...................         56,416          74,321          81,466        142,103         (61,243)
</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)    Basic per share amounts have been computed by dividing net earnings
       after preferred dividends by the weighted average number of shares
       outstanding: 14,190 in 1994; 17,932 in 1995; 20,179 in 1996; 21,693 in
       1997; and 25,604 in 1998, respectively.

(4)    Diluted per share amounts have been computed by dividing net earnings
       after preferred dividends by the weighted average number of shares
       outstanding including common stock equivalents, consisting of stock
       options and warrants, when their effect is dilutive: 14,190 in 1994;
       17,932 in 1995; 20,342 in 1996; 22,334 in 1997; and 25,604 in 1998,
       respectively.

(5)    Amount for 1995 includes $17,421 related to net assets of discontinued
       operations. Amount for 1998 includes $384,031 related to current portion
       of long-term debt due to default under the Company's existing credit
       agreement.


                                      22
<PAGE>   23

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 included elsewhere herein. Certain
information contained herein, including information with respect to the
Company's plans and strategy for its business, are forward-looking statements.
See "Forward-Looking Statements".

SUBSEQUENT EVENTS

       See "Liquidity and Capital Resources" for a description of certain
events affecting the current liquidity of the Company.

COMPANY HISTORY

       The Company was incorporated in June 1993 under the laws of the State of
Texas and conducts a majority of its operations through CRI.

       In December 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. 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 $16.1 million. The acquisition of ING was accounted
for using the purchase method.

       In April 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 up
to $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.

       On October 3, 1997, the Company issued 5,000,000 shares of common stock
at $10.50 per share and issued $150 million of 8 7/8% Senior Subordinated Notes
due 2007 ("Senior Notes") pursuant to two public offerings with combined net
proceeds of $193.7 million. The proceeds from these offerings were used to repay
$144.8 million of indebtedness outstanding under the Company's Revolving Credit
Facility, for general corporate purposes and to fund a portion of the December
1997 Oklahoma property acquisition discussed below.

       Effective December 31, 1997, the Company acquired from Amoco Production
Company ("Amoco") interests in certain crude oil and natural gas properties
("Oklahoma Properties") located primarily in southern Oklahoma for cash
consideration of approximately $257.5 million and warrants to purchase one
million shares of common stock at $10.425 per share for a period of five years
valued at $3.4 million. The Oklahoma Properties are in more than 25,000 gross
acres concentrated in southern Oklahoma, including 14 major producing oil
fields. Of the 14 major producing fields, the Company is operator of eleven
fields and at December 31, 1998 had an average working interest in the fields it
operates of approximately 73%.

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

GENERAL

       The Company seeks to acquire controlling interests in underdeveloped
crude oil and natural gas properties and attempts to maximize reserves and
production from such properties through relatively low-risk activities such as
development drilling, multiple completions, recompletions, workovers,
enhancement of production facilities and secondary recovery projects. The
Company's only operating revenues are crude oil and natural gas sales with
crude


                                      23
<PAGE>   24

oil sales representing approximately 75% of production revenues and natural gas
sales representing approximately 25% of production revenues during 1996 and
1997, and crude oil sales representing approximately 77% of production revenues
and natural gas sales representing approximately 23% of production revenues
during 1998. Approximately 60% of natural gas sales revenues during 1998 were
attributable to the Monroe field gas properties which were sold in December
1998. Operating revenues increased from $26.5 million in 1994 to $68.8 million
in 1998 primarily due to an increase in production volumes from successful
development and exploration activities in the Company's existing Mississippi
fields and due to the following acquisitions: the December 1994 acquisition of
the Monroe natural gas field; the August 1995 acquisition of the Brookhaven
field and; the December 1997 acquisition of the Oklahoma Properties.

       The Company also strives to maintain a low cost structure through asset
concentration, such as in the interior salt basin of Mississippi and the
Oklahoma Properties. Asset concentration permits operating economies of scale
and leverages operational, technical and marketing capabilities. Production
costs (including lease operating expenses and production taxes) per BOE have
decreased from $4.49 in 1994 to $4.18 in 1998.

       The price received by the Company for crude oil and natural gas may vary
significantly during certain times of the year due to the volatility of the
crude oil and natural gas market, particularly during the cold winter and hot
summer months. As a result, the Company has entered, and expects to continue to
enter, into forward sale agreements or other arrangements for a portion of its
crude oil and natural gas production to hedge its exposure to price
fluctuations, though at December 31, 1998, the Company was not a party to any
forward sale agreements or other arrangements. It is unlikely that the Company
will be able to enter into any forward sales agreements or other similar
arrangements until it remedies its current liquidity problems because of the
associated credit risks of the counterparty to such agreements. See "Liquidity
and Capital Resources." While the Company's hedging program is intended to
stabilize cash flow and thus allow the Company to plan its capital expenditure
program with greater certainty, 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. Because all hedging
transactions are tied directly to the Company's crude oil and natural gas
production and natural gas marketing operations, the Company does not believe
that such transactions are of a speculative nature. Gains and losses on these
hedging transactions are reflected in crude oil and natural gas revenues at the
time of sale of the hedged production. Any gain or loss on the Company's crude
oil hedging transactions is determined as the difference between the contract
price and the average closing price for West Texas Intermediate ("WTI") crude
oil on the New York Mercantile Exchange ("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 on NYMEX for the last three days during the month in which the
hedge is in place. Consequently, hedging activities do not affect the actual
price received for the Company's crude oil and natural gas.

       The Company also controls the magnitude and timing of its capital
expenditures by obtaining high working interests in and operating its
properties. At December 31, 1998, the Company owned an average working interest
of 76% in the fields it operates.


                                      24
<PAGE>   25

RESULTS OF OPERATIONS

       SELECTED OPERATING DATA

<TABLE>
<CAPTION>
                                                          YEAR ENDED DECEMBER 31,
                                                     ------------------------------
                                                      1996        1997        1998
                                                     ------      ------      ------
<S>                                                <C>          <C>         <C>   
PRODUCTION:
   Crude oil (Bbl/day) ......................        6,742        7,726       13,889
   Natural gas (Mcf/day) ....................       18,160       21,003       22,260
        BOE (Bbl/day) .......................        9,769       11,227       17,599

AVERAGE SALES PRICES:
   Crude oil (per Bbl) ......................      $ 16.42      $ 16.31      $ 10.40
   Natural gas (per Mcf) (a) ................         2.07         2.23         1.98

PER BOE DATA:
   Production costs (b) .....................      $  3.88      $  3.90      $  4.18
   Depletion ................................         4.55         4.69         4.38

PRODUCTION REVENUES (IN THOUSANDS):
   Crude oil ................................      $40,527      $45,991      $52,689
   Natural gas ..............................       13,745       17,139       16,070
                                                   -------      -------      -------
        Total production revenues ...........      $54,272      $63,130      $68,759
                                                   =======      =======      =======
</TABLE>
---------------
(a) Natural gas prices are net of fuel costs used in gas gathering.

(b) Includes lease operating expenses and production taxes, exclusive of
    general and administrative costs.

YEAR ENDED DECEMBER 31, 1998 COMPARED WITH YEAR ENDED DECEMBER 31, 1997

       Operating Revenues. During 1998, production revenues increased 9% to
$68.8 million as compared to $63.1 million in 1997. This increase was
principally due to an 80% increase in crude oil production and a 6% increase in
natural gas production, substantially offset by decreases in the prices
received for crude oil and natural gas (including hedging gains and losses
discussed below) of 36% and 11%, respectively.

       The 6% increase in daily natural gas production is primarily due to a
26% increase in production as a result of the December 1997 acquisition of the
Oklahoma Properties, substantially offset by production declines on the
Company's Brookhaven, Martinville, North Padre and Monroe fields. Additionally,
the Monroe field was sold to an unaffiliated third party on December 2, 1998,
resulting in lower gas production for the year of 1998 as compared to the year
of 1997. The Monroe field represented 85% and 67% of the Company's gas
production in 1997 and 1998, respectively. The 80% increase in daily crude oil
production during 1998 is primarily due to a 76% increase in production as a
result of the acquisition of the Oklahoma Properties. Although the Company
increased crude oil production during the first three quarters of 1998 as
compared to the same period in 1997 in the Martinville and Brookhaven fields,
such increases were substantially offset by fourth quarter 1998 crude oil
production declines of 21% on its Mississippi fields as compared to the fourth
quarter of 1997 as well as overall crude oil production declines in the Soso
and Summerland fields throughout 1998 as compared to 1997.

       Crude oil and natural gas production declined in the fourth quarter of
1998 from an average of 18,495 BOE per day during the first nine months of 1998
to 14,939 BOE per day during the fourth quarter of 1998 due to the December
1998 sale of the Monroe field natural gas properties and due to overall
production declines in the operated Mississippi and Oklahoma properties. Due to
the Company's capital restraints in conjunction with the decline in crude oil
prices, the Company significantly reduced both minor and major well repairs on
its operated properties during the last five months of 1998 and ceased all well
repairs in December 1998, resulting in overall production declines. The
Company's crude oil and natural gas production level was approximately 11,400
BOE per day in January 1999. The Company does not anticipate any improvement in
production and will experience further production declines, until funds are
available for well repairs and additional development activity.


                                      25
<PAGE>   26

       Average crude oil prices realized in 1998, including hedging gains and
losses discussed below, decreased from 1997 due to declining oil prices which
can be attributed to several factors, including: a lack of cold weather in the
1998 winter months, increased storage inventories and perceptions of the
effects of increased quotas or lack of adherence to quotas from the
Organization of Petroleum Exporting Countries. The posted price for the
Company's crude oil averaged $11.32 per Bbl in 1998, a 38% decrease over the
average posted price of $18.34 per Bbl experienced in 1997. The price per Bbl
received by the Company is adjusted for the quality and gravity of the crude
oil and is generally lower than the posted price.

       The realized price for the Company's natural gas, including hedging
gains and losses discussed below, decreased 11% from $2.23 per Mcf in 1997 to
$1.98 per Mcf in 1998 due to a lack of cold weather and market volatility.

       Production revenues for 1998 included no crude oil hedging gains or
losses compared to crude oil hedging losses of $.3 million ($.11 per Bbl) in
1997. Production revenues in 1998 included natural gas hedging gains of $.5
million ($.06 per Mcf) compared with natural gas hedging gains of $.1 million
($.01 per Mcf) for 1997. 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 decreased to $214,000 in 1998 from $646,000 in
1997 primarily due to a decline of interest received on cash investments in
1998. In 1997, $137,000 of interest was received by the Company in the first
quarter on a federal tax refund and $465,000 of interest was earned in the
fourth quarter on cash investments.

       Expenses. Production expenses (including production taxes) were $26.9
million for 1998 compared to $16 million for 1997. On a BOE basis, production
costs increased to $4.18 per BOE in 1998 compared to $3.90 per BOE in 1997. The
increase in expenses between years is primarily due to an increase of
approximately $11.8 million relating to the December 1997 acquisition of the
Oklahoma Properties, partially offset by reduced operating costs on the
Company's Mississippi properties due to the improved operating efficiencies and
due to a reduction of repairs imposed by the Company during the last half of
1998 due to the decline in crude oil prices.

       General and administrative costs increased 8% from $7.2 million in 1997
to $7.8 million in 1998 primarily due to increased personnel costs due to staff
additions to handle the increased capital activities in Mississippi during the
first half of 1998 and the December 1997 acquisition of the Oklahoma Properties
and due to the accrual of a $.4 million fee related to the termination of a
drilling contract which extended through mid-year 1999, partially offset by an
increase in capitalization of salaries and other general and administrative
costs directly associated with the Company's exploration and development
activities.

       Allowance for bad debt in 1998 represents an allowance for uncollectible
accounts receivable from working interest owners and an allowance for director
and employee receivables as discussed in Note 11 of the Notes to the
Consolidated Financial Statements contained elsewhere herein.

       Unsuccessful transaction costs of $2.1 million incurred in 1998 relate
to the termination of an agreement in which the Company was to issue $250
million of equity. Such costs are comprised of $1.2 million for financial
advisory services in conjunction with such transaction, $.5 million for an
outside financial advisor regarding the fairness of the agreement and $.4
million for legal, accounting and other services.

       Interest expense increased 296% in 1998 compared to 1997, due to higher
borrowing levels during 1998 as compared to 1997 and due to the sale of $150
million of Senior Notes on October 3, 1997, which bear a higher interest rate
than the Company's revolving credit facility. The average interest rate paid on
outstanding indebtedness was 8.07% in 1998, compared to 7.84% in 1997. The
borrowing levels increased throughout 1997 and 1998 due to additional
borrowings to fund the Company's capital expenditure program and the December
1997 acquisition of the Oklahoma Properties.

       Depletion and depreciation expense increased 46% to $28.1 million in
1998 from $19.2 million in 1997. These increases are primarily the result of
increased production volumes partially offset by a decreased rate per BOE,
which 


                                      26
<PAGE>   27

decreased to $4.38 in 1998, compared with $4.69 in 1997. The depletion and
depreciation rate per BOE decreased between years due to the writedowns of oil
and gas properties in 1998 as discussed below.

       In accordance with generally accepted accounting principles, at a point
in time coinciding with the quarterly and annual reporting periods, the Company
must test the carrying value of its crude oil and natural gas properties, net
of related deferred taxes, against a calculated amount based on estimated
reserve volumes valued at then current realized prices held flat for the life
of the properties discounted at 10% per annum plus the lower of cost or
estimated fair value of unproved properties (the "cost center ceiling"). If the
carrying value exceeds the cost center ceiling, the excess must be expensed in
such period and the carrying value of the oil and gas reserves lowered
accordingly. Amounts required to be written off may not be reinstated for any
subsequent increase in the cost center ceiling. During 1998, the carrying
values exceeded the cost center ceilings, resulting in non-cash writedowns of
the crude oil and natural gas properties, aggregating $188 million, including
$32 million, $41 million and $115 million recognized in the first, second and
fourth quarters of 1998, respectively.

       Current tax expense of $4.1 million in 1998 primarily relates to state
income taxes due on the December 1998 sale of the Monroe field natural gas
properties and related gas gathering systems.

       The Company's net operating loss carryforwards ("NOLs") for United
States and Canadian federal income tax purposes were approximately $64.9
million at December 31, 1998 and expire between 1999 and 2018. Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes"
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." A valuation allowance has been established for the entire balance of
these NOLs as it is uncertain whether they will be utilized before they expire.

       The Company's net loss for 1998 was $203.3 million, as compared to net
earnings of $6.3 million for 1997, for the reasons discussed above.

YEAR ENDED DECEMBER 31, 1997 COMPARED WITH YEAR ENDED DECEMBER 31, 1996

       Operating Revenues. During 1997, production revenues increased 16% to
$63.1 million as compared to $54.3 million in 1996. This increase was
principally due to a 15% increase in crude oil production, a 16% increase in
natural gas production and an increase in the price received for natural gas
(including hedging gains and losses discussed below) of 8%.

       The 16% increase in daily natural gas production is primarily a result
of the continued positive response from the Company's development efforts in
the North Padre, Martinville and Brookhaven fields. The 15% increase in daily
crude oil production during 1997 is due to significant production increases
made in the Martinville, Soso and Brookhaven fields, with production increasing
by 125%, 51% and 87%, respectively, in such fields. These production increases
were partially offset by a production decrease in the Summerland field due to
the unusually high frequency of weather-related power outages and mechanical
problems during the first quarter of 1997 and normal production declines due to
the maturity of the field.

       Average crude oil prices realized in 1997, including hedging gains and
losses discussed below, remained comparable to 1996. Even though posted crude
oil prices received in 1997 declined from 1996 prices, the average prices
realized in 1996 and 1997 were comparable due to crude oil hedging losses
experienced in 1996. The posted price for the Company's crude oil averaged
$18.34 per Bbl in 1997, a 9% decrease over the average posted price of $20.23
per Bbl experienced in 1996. The price per Bbl received by the Company is
adjusted for the quality and gravity of the crude oil and is generally lower
than the posted price.

       The realized price for the Company's natural gas, including hedging
gains and losses discussed below, increased 8% from $2.07 per Mcf in 1996 to
$2.23 per Mcf in 1997. Although the average natural gas prices received, net of
fuel used in gathering, in 1996 and 1997 were comparable at $2.25 per Mcf and
$2.22 per Mcf, respectively, the natural gas hedging losses in 1996 reduced the
realized price in 1996 by $.18 per Mcf while 1997 hedging gains increased the
realized price in 1997 by $.01 per Mcf.

       Production revenues for 1997 included crude oil hedging losses of $.3
million ($.11 per Bbl) compared to crude oil hedging losses of $4.7 million
($1.92 per Bbl) in 1996. Production revenues in 1997 also included natural gas
hedging gains of $.1 million ($.01 per Mcf) compared with natural gas hedging
losses of $1.2 million ($.18 per Mcf) for 1996.


                                      27
<PAGE>   28

       Interest and other income decreased to $646,000 in 1997 from $1 million
in 1996 primarily 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 in 1996,
partially offset by $137,000 of interest received in the first quarter of 1997
on a federal tax refund and $465,000 of interest earned in the fourth quarter
of 1997 on cash investments.

       Expenses. Production expenses (including production taxes) were $16
million for 1997 compared to $13.9 million for 1996. This increase primarily
reflects additional production volumes. On a BOE basis, production costs
increased to $3.90 per BOE in 1997 compared to $3.88 per BOE in 1996.

       General and administrative costs decreased 1% between years from $7.3
million in 1996 to $7.2 million in 1997. General and administrative costs
expensed in 1997 were less than such costs expensed in 1996, even though total
general and administrative costs increased, due to an increase in the
capitalization of salaries and other general and administrative costs directly
associated with the Company's increased exploration and development activities.
Total general and administrative cost increased due to higher compensation and
employee related costs attributable to staff additions and higher professional
fees.

       Interest expense increased 31% in 1997 compared to 1996, due to higher
borrowing levels during 1997 as compared to 1996 and due to the sale of $150
million of 8 7/8% Senior Subordinated Notes ("Senior Notes") on October 3, 1997
which bear a higher interest rate than the Company's revolving credit facility.
The average interest rate paid on outstanding indebtedness was 7.84% in 1997,
compared to 7.6% in 1996.

       Depletion and depreciation expense increased 18% to $19.2 million in
1997 from $16.3 million in 1996. These increases are primarily the result of
increased production volumes and an increased rate per BOE, which increased to
$4.69 in 1997, compared with $4.55 in 1996.

       Based on the cost center ceiling test at December 31, 1997, using the
year end WTI posted reference price of $16.17 per Bbl of crude oil and a year
end price of $2.26 per Mcf of natural gas, the carrying value of the crude oil
and natural gas properties were lower than the cost center ceiling therefore no
writeoff was required.

       The Company's net earnings for 1997 were $6.3 million, as compared to
net earnings of $5.9 million for 1996, for the reasons discussed above.

LIQUIDITY AND CAPITAL RESOURCES

       Capital Sources. Cash flow generated from operating activities was $37.1
million and $691,000 for the years ended December 31, 1997 and 1998,
respectively. Operating revenues, net of lease operating expenses, production
taxes and general and administrative expenses decreased $5.8 million (15%)
during 1998 from 1997, despite a 57% increase in equivalent production between
years, primarily due to price decreases during 1998 from 1997 of 36% and 11%
for crude oil and natural gas, respectively. Additionally, interest expense
increased $22.2 million between periods as a result of borrowings to finance
the Company's capital expenditure program and the December 1997 acquisition of
the Oklahoma Properties. Changes in operating assets and liabilities provided
$4.6 million of cash for operating activities for the year ended December 31,
1998, primarily due to the increase in federal and state taxes payable and
accrued interest payable, partially offset by the increase in cash in escrow
and the decrease in other accrued liabilities. See "Results of Operations" for
a discussion of operating results.

       On December 2, 1998, the Company sold its natural gas assets, including
its natural gas properties and the related gas gathering systems, located in
Monroe, Louisiana for approximately $61.5 million. Proceeds from the sale were
used to reduce borrowings under the Company's Revolving Credit Facility.

       As discussed more fully under "Results of Operations for the Year Ended
December 31, 1998 Compared with the Year Ended December 31, 1997", operating
revenues have been declining during 1998 due to crude oil and natural gas price
declines. Additionally, the Company's crude oil and natural gas production has
declined from an average of 18,495 BOE per day during the first nine months of
1998 to approximately 11,400 BOE per day during January 1999


                                      28
<PAGE>   29

due to the sale of the Monroe field gas properties in December 1998, which
contributed approximately 2,670 BOE per day during the first nine months of
1998, due to overall production declines on the Company's operated properties in
Oklahoma and Mississippi as a result of the decrease and ultimate cessation of
well repair work during the last five months of 1998 and due to the Company
halting production on wells which are uneconomical due to depressed crude oil
prices. The Company does not anticipate any improvement in production and will
experience further production declines, until funds are available for well
repairs and additional development activity.

       Based on the January 1999 production level of approximately 11,400 BOE
per day and the average price received in January 1999 of approximately $8.30
per barrel of crude oil and $1.92 per mcf of natural gas, the Company's
operating revenues are adequate to cover lease operating expenses, production
taxes and general and administrative expense but are not sufficient to cover
interest accruing on the Senior Notes or on the borrowings under the Revolving
Credit Facility. See "-Future Operations".

       At December 31, 1998, the Company had a working capital deficit of
$387.9 million primarily due to the reclassification of all long term debt to
current maturities as discussed below. See "-Future Operations".

       In August 1998, the Company announced that it had reached an agreement
to issue $250 million of common stock at $6.00 per share to HM4 Coho L.P. On
December 15, 1998, the Company announced that HM4 Coho L.P. was terminating the
prior agreement and that the Company was considering a restructuring of the HM4
Coho L.P. agreement, which had received shareholder approval, to reflect an
increase in the number of shares that the Company would issue for the $250
million purchase price based on a price per share of $4.00 versus $6.00. After
working through all of the issues and reaching a verbal agreement with all of
the interested parties with regard to the proposed restructuring, the Company
was informed by HM4 Coho L.P. on February 12, 1999 that it was no longer
interested in the investment.

       Under the Revolving Credit Facility, at December 31, 1998, the amount
available to the Company in borrowing capacity for general corporate purposes
("Borrowing Base") was $242 million. The Revolving Credit Facility terminates
on January 2, 2003. The margin premium charged in excess of LIBOR for revolving
Eurodollar advances is based on a ratio calculated on a rolling four-quarter
basis of consolidated indebtedness to EBITDA. Amounts outstanding up to $220
million under the Revolving Credit Facility accrue interest at the option of
the Company at (i) LIBOR plus a maximum of 1.50% or (ii) the prime rate.
Amounts outstanding in excess of $220 million accrue interest at the option of
the Company at (i) LIBOR plus 2.50% or (ii) the prime rate plus 1%. CRI, and
its wholly owned subsidiaries, Coho Louisiana Production Company, Coho
Exploration, Inc. and Coho Oil & Gas, Inc., are the borrowers under the
Revolving Credit Facility and the repayment of all advances is guaranteed by
Coho Energy, Inc. Outstanding advances under the Revolving Credit Facility are
secured by substantially all of the assets of the Company. At December 31,
1998, the Revolving Credit Facility lenders were Banque Paribas, Houston
Agency; Bank One, Texas, N.A.; MeesPierson Capital Corp.; Bank of Scotland; Den
Norske Bank; Christiania Bank; Credit Lyonnais and Toronto Dominion Bank. At
December 31, 1998, outstanding advances under the Company's Revolving Credit
Facility were $235 million and increased to $239.6 million as of January 5,
1999.

       On February 22, 1999, the Company was informed by the lenders under the
Revolving Credit Facility that the Borrowing Base was reduced to $150 million
effective January 31, 1999 creating an over advance under the new Borrowing
Base of $89.6 million. Under the terms of the Revolving Credit Facility, the
Company was required to cure the over advance amount by March 2, 1999 by either
(a) providing collateral with value and quantity in amounts equal to such
excess, (b) prepaying, without premium or penalty, such excess plus accrued
interest or (c) paying the first of five equal monthly installments to repay
the over advance.

       The Company was unable to cure the over advance as required by the
Revolving Credit Facility by March 2, 1999. On March 8, 1999, the Company
received written notice from the lenders under the Revolving Credit Facility
that it was in default under the terms of the Revolving Credit Facility and the 
lenders reserved all rights, remedies and privileges as a result of the payment
default. Additionally, as a result of the payment default, the past due
payments under the Revolving Credit Facility will bear interest at the default
interest rate of prime plus 4%. Although the lenders have not accelerated the
full amount outstanding under the Revolving Credit Facility, the outstanding
advances of $235 million as of December 31, 1998 have been reclassified to
current maturities because the Company is currently unable to cure the default
within the required terms. The Company is currently in discussions with the
lenders under the Revolving Credit Facility to work with the Company in
restructuring this repayment schedule so that the Company can continue to
pursue alternative arrangements. See "-Future Operations".


                                       29
<PAGE>   30

       The Revolving Credit Facility contains certain financial and other
covenants including (i) the maintenance of minimum amounts of shareholders'
equity ($108 million plus 50% of the accumulated consolidated net income
beginning in 1998 for the cumulative period excluding adjustments for any write
down of property, plant and equipment, plus 75% of the cash proceeds of any
sales of capital stock of the Company), (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, 1998, the Company was not in compliance
with the cash flow to interest expense and current asset to current liability
covenants.

       The $150 million of Senior Notes are unsecured senior subordinated
obligations of the Company and rank pari passu in right of payment to all
existing and future senior subordinated indebtedness of the Company. The Senior
Notes mature on October 15, 2007 and bear interest from October 3, 1997 at the
rate of 8 7/8% per annum payable semi-annually, commencing on April 15, 1998.
Certain subsidiaries of the Company issued guarantees of the Senior Notes on a
senior subordinated basis. The indenture issued in conjunction with the Senior
Notes (the "Indenture") contains certain covenants, including covenants that
limit (i) indebtedness, (ii) restricted payments, (iii) distributions from
restricted subsidiaries, (iv) transactions with affiliates, (v) sales of assets
and subsidiary stock (including sale and leaseback transactions), (vi)
dividends and other payment restrictions affecting restricted subsidiaries and
(vii) mergers or consolidations.

       As a result of the payment default under the Revolving Credit Facility
discussed above, the Company may be in default under the terms of the Senior
Notes specified in the Indenture. If the Company is in default of the Senior
Notes as a result of the payment default under the Revolving Credit Facility,
the Company will be required to deliver a written notice to the Trustee of the
Senior Notes within 30 days after the occurrence of the event of default in the
form of an officers' certificate indicating an event of default has occurred
and is continuing and what action the Company is taking or proposing to take
with respect to the event of default. Under an event of default of the Senior
Notes, the Trustee by written notice to the Company, or the holders of at least
25% in principal amount of the outstanding Senior Notes, may declare the
principal and accrued interest on all the Senior Notes due and payable
immediately. However, the Company may not pay the principal of, premium (if
any) or interest on the Senior Notes so long as any required payments due on
the Revolving Credit Facility remain outstanding and have not been cured or
waived. All amounts outstanding under the Senior Notes as of December 31, 1998
have been classified as current maturities because the Company is currently
unable to cure the existing or pending default within the required terms of the
Indenture.

       Future Operations. The Company is exploring its alternatives to resolve
its current liquidity problems, including (a) the current default under the
Revolving Credit Facility, (b) the potential acceleration of all amounts due
under the Revolving Credit Facility and the Senior Notes, and (c) inadequate
cash flow from operations to support upcoming interests payments due on the
Revolving Credit Facility on April 6, 1999 and on the Senior Notes due on April
15, 1999 or to meet other accrued liabilities as they become due. The
alternatives available to the Company include, but are not limited to, the
conversion of a portion or all of the $150 million of the Senior Notes to
equity, raising additional equity and/or refinancing the Company's Revolving
Credit Facility to make overdue principal and interest payments on its
indebtedness and to provide additional capital to fund repairs on and the
continued development of the Company's properties. The Company is also
evaluating cost reduction programs to enhance cash flow from operations. There
can be no assurance that the Company will be successful in resolving its
liquidity problems through the alternatives set forth above and may seek
protection under Chapter 11 of the United States Bankruptcy Code while it is
pursuing other financing and/or reorganization alternatives. These factors,
among others, raise substantial doubt concerning the ability of the Company to
continue as a going concern.

       Dividends. While the Company is restricted on the payment of dividends
under the Revolving Credit Facility, dividends are permitted on Company equity
securities provided (i) the Company is not in default under the Revolving
Credit Facility; 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,
1994 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. The
Indenture limits the Company's ability to pay dividends, based on the Company's
ability to incur additional indebtedness and primarily limited to 50% of
consolidated net income earned, excluding any write down of property, plant and
equipment after the date the Senior Notes were issued plus the net proceeds
from any future sales of capital stock of the Company. Due to the Company's
default under the Revolving Credit Facility and due to the Company's current
and expected capital needs as discussed above, it is unlikely that the Company
will pay dividends in the foreseeable future.


                                       30
<PAGE>   31
       Capital Expenditures. During 1998, the Company incurred capital
expenditures of $70.1 million compared with $72.7 million in 1997. The capital
expenditures incurred during 1998 were largely in connection with the
continuing development efforts, including recompletions, workovers and
waterfloods, on existing wells in the Company's Brookhaven, Laurel,
Martinville, Summerland, Bumpass, Tatums, East Fitts, North Alma Deese and
Sholem Alechem fields. In addition, during 1998, the Company drilled 42 wells,
including sixteen producing oil wells, one producing gas well and three dry
holes in the Mississippi fields; eleven producing oil wells, five producing gas
wells and one dry hole in the Oklahoma fields; and two producing gas wells and
three dry holes in the Monroe, Louisiana field.

       General and administrative costs directly associated with the Company's
exploration and development activities were $4.1 million and $5.7 million for
the years ended December 31, 1997 and 1998, respectively, and were included in
total capital expenditures.

       The Company is in the process of finalizing the location for an
exploratory well on its Anaguid permit in Tunisia, North Africa. A well must be
drilled by June 1999 or the acreage concession will expire. The Company's
estimated net cost to drill is approximately $2.5 million and the Company's net
carrying cost for its investment in the Anaguid permit is approximately $5.7
million as of December 31, 1998. If the Company is unable to drill this well by
June 1999 and the acreage concession expires, the Company will incur a liability
of approximately $4.0 million for unfulfilled commitments, of which $3.7 million
is due to the Tunisian government. Although the Company intends to drill this
well, the Company cannot currently predict whether it will have the financial
resources to make these expenditures. The Company has not entered into any other
capital commitments in 1999 due to its liquidity problems discussed above.

       Hedging Activities. Crude oil and natural 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 crude oil and natural gas, the Company has
entered, and expects to continue to enter, into crude oil and natural gas
hedging transactions. It is unlikely that the Company will be able to enter
into any forward sales agreements or other similar arrangements until it
remedies its current liquidity problems because of the associated credit risks
of the counterparty to such agreements. See "Liquidity and Capital Resources."
The Company's hedging program is intended to stabilize cash flow and thus allow
the Company to minimize its exposure to price fluctuations. Because all hedging
transactions are tied directly to the Company's crude oil and natural gas
production, the Company does not believe that such transactions are of a
speculative nature. Gains and losses on these hedging transactions are reflected
in crude oil and natural gas revenues at the time of sale of the hedged
production. Any gain or loss on the Company's natural gas hedging transactions
is generally determined as the difference between the contract price and the
average settlement price on NYMEX for the last three days during the month in
which the hedge is in place. At December 31, 1998, the Company has no natural
gas or crude oil production hedged and there were no deferred or unrealized
hedging gains or losses.

       The Company will be required to adopt SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" for fiscal year ended 2000. If
the Company had adopted SFAS No. 133 during 1998, there would be no effect as
the Company has no hedges outstanding at December 31, 1998. Although the future
impact of adopting SFAS No. 133 has not been determined yet, the Company
believes that the impact will not be material.


       Year 2000 Issue. The Company, like other businesses, is facing the Year
2000 issue. Many computer systems and equipment with embedded chips or
processors use only two digits to represent the calendar year. This could
result in computational or operational errors because date sensitive systems
will recognize the year 2000 as 1900 or not at all. This inability to recognize
or properly treat the year 2000 may cause systems to process critical financial
and operational information incorrectly.

       State of Readiness. The Company has divided its Year 2000 review into
five separate elements: accounting computer systems, network infrastructure,
desktop computers at corporate headquarters, field operational systems and major
suppliers and purchasers. The Company has completed its Year 2000 review and
remediation with respect to the 





                                       31
<PAGE>   32

first three elements and has determined that accounting computer systems,
network infrastructure and desktop computers at the corporate headquarters are
Year 2000 compliant.

       The Company is continuing its review of field operational systems. All
networks and communications systems and infrastructure in the field are now
compliant.  Upgrades on the production reporting system for Year 2000 compliance
are completed and testing is in its final phase.  Desktop computers in the field
are 80% compliant with full compliance projected in the second quarter of 1999.
The field automation equipment in the Company's Oklahoma division was found to
be non-compliant. Quotes for all needed upgrades have been received, and the
Oklahoma division is expected to be compliant by mid-1999. The Company
estimates that it is 100% complete with its review, and is 75% complete with its
remediation of field operational systems and expects to have complete Year 2000
certification in this element by mid-year 1999.

       The Company is concurrently reviewing Year 2000 compliance of major
suppliers and purchasers. The Company has contacted its major suppliers and
purchasers by letter and has asked for a written response from them describing
their Year 2000 readiness efforts. To date, the Company has not identified any
material problems associated with the Year 2000 readiness efforts of its major
suppliers and purchasers. The Company estimates that it is 40% complete with
its review of major suppliers and purchasers. Though some suppliers and
purchasers have not yet completed their Year 2000 readiness efforts, the Company
expects to be substantially complete with its Year 2000 certification for this
element by the third quarter of 1999.

       In addition, the Company is currently working on a contingency plan that
addresses potential Year 2000 problems both within the Company and with major
suppliers and purchasers of the Company. The Company anticipates that the
contingency plan will be in place by the third quarter of 1999.

       Cost. The Company began its Year 2000 Program in 1997, and has
incorporated its preparations into its normal equipment upgrade cycle. As a
result, the historical cost of the Company's Year 2000 efforts to date has not
been material. Management does not estimate future expenditures related to the
Year 2000 to be material.

       Risks. The Company believes that it is taking all reasonable steps to
ensure Year 2000 readiness. Its ability to meet the projected goals, including
the costs of addressing the Year 2000 issue and the dates upon which compliance
will be attained, depends on the Year 2000 readiness of its key suppliers and
customers and the successful development and implementation of contingency
plans. Although these and other unanticipated Year 2000 issues could have an
adverse effect on the results of operations or financial condition of the
Company, it is not possible to estimate the extent of impact at this time, since
the contingency plans are still under development.

       ALL STATEMENTS REGARDING YEAR 2000 MATTERS CONTAINED IN THIS ANNUAL
REPORT ON FORM 10-K ARE "YEAR 2000 READINESS DISCLOSURES" WITHIN THE MEANING OF
THE YEAR 2000 INFORMATION AND READINESS DISCLOSURE ACT.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

       Price Fluctuations. The Company's result of operations are highly
dependent upon the prices received for crude oil and natural gas production.
The Company has entered, and expects to continue to enter, into forward sale
agreements or other arrangements for a portion of its crude oil and natural gas
production to hedge its exposure to price fluctuations. At December 31, 1998,
the Company was not a party to any forward sale agreements or other
arrangements. It is unlikely that the Company will be able to enter into any
forward sales agreements or other similar arrangements until it remedies its
current liquidity problems because of the associated credit risks of the
counterparty to such agreements. See "Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations".

       Interest Rate Risk. Total debt as of December 31, 1998, included $235
million of floating-rate debt attributed to bank credit facility borrowings. As
a result, the Company's annual interest cost in 1999 will fluctuate based on
short-term interest rates. 





                                       32
<PAGE>   33

The impact on annual cash flow of a ten percent change in the floating interest
rate (approximately 73 basis points) would be approximately $1.7 million
assuming outstanding debt of $235 million throughout the year.

       Total debt as of December 31, 1998, also included $149 million (net of $1
million of unamortized original issue discount) of fixed rate Senior Notes with
an estimated fair market value of $57 million based on quoted prices from market
sources.

       The Company is in default under its bank credit facility and may be
default under its Senior Notes.  See "Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations".




                                       33
<PAGE>   34

ITEM 8.  FINANCIAL STATEMENTS

<TABLE>
<S>                                                                        <C>
Report of Independent Public Accountants ................................   35

Consolidated Balance Sheets, December 31, 1997 and 1998 .................   36

Consolidated Statements of Operations, Years Ended December 31, 1996, 
1997 and 1998 ...........................................................   37

Consolidated Statements of Shareholders' Equity, Years Ended 
December 31, 1996, 1997 and 1998 ........................................   38

Consolidated Statements of Cash Flows, Years Ended December 31, 
1996, 1997 and 1998 .....................................................   39

Notes to Consolidated Financial Statements, Years Ended December 
31, 1996, 1997 and 1998 .................................................   40
</TABLE>




                                       34
<PAGE>   35

                    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 as of December 31, 1997 and
1998, and the related consolidated statements of operations, shareholders'
investments and cash flows for each of the three years in the period ended
December 31, 1998. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

       We conducted our audits in accordance with 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
statements presentation. We believe that our audits provide a reasonable basis
for our opinion.

       In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Coho Energy, Inc.
and subsidiaries as of December 31, 1997 and 1998, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted accounting principles.

       The accompanying financial statements have been prepared assuming that
the Company will continue as a going concern. As discussed in Note 2 to the
financial statements, the Company has suffered recurring losses from operations,
has received a notice of default from its lenders under its existing bank credit
facility and may be in default under the terms of its 8 7/8% Senior Subordinated
notes, and projects negative cash flow from operations in 1999 that raise
substantial doubt about the Company's ability to continue as a going concern.
Management's plans in regard to these matters are also described in Note 2. The
financial statements do not include any adjustments relating to the
recoverability and classification of asset carrying amounts or the amount and
classification of liabilities that might result should the Company be unable to
continue as a going concern.


                                         Arthur Andersen LLP

Dallas, Texas
March 24, 1999




                                       35
<PAGE>   36

                               COHO ENERGY, INC.
                                AND SUBSIDIARIES

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

                                     ASSETS
<TABLE>
<CAPTION>
                                                                                         DECEMBER 31
                                                                                    ---------------------
                                                                                     1997           1998
                                                                                    ------         ------
<S>                                                                               <C>             <C>
Current assets
  Cash and cash equivalents ................................................      $   3,817       $   6,901
  Cash in escrow ...........................................................             --           1,505
  Accounts receivable, principally trade ...................................         10,724           9,960
  Deferred income taxes ....................................................          1,818              --
  Other current assets .....................................................            715             948 
                                                                                  ---------       ---------
                                                                                     17,074          19,314
Property and equipment, at cost net of accumulated depletion and
depreciation, based on full cost accounting method (note 3) ................        531,409         324,574
Other assets ...............................................................          6,645           6,180   
                                                                                  ---------       --------- 
                                                                                  $ 555,128       $ 350,068 
                                                                                  =========       ========= 
                      LIABILITIES AND SHAREHOLDERS' EQUITY

  Current liabilities
  Accounts payable, principally trade ......................................      $   4,888       $   5,577
  Accrued liabilities and other payables ...................................          7,545           5,970
  Accrued interest .........................................................          3,901           7,302
  Accrued compensation .....................................................          1,423              --
  Accrued environmental costs ..............................................          1,300             686
  Federal and state income taxes payable ...................................             --           4,045
                                                                                         38         384,031
                                                                                  ---------       --------- 
                                                                                     19,095         407,611
Long term debt, excluding current portion (note 4) .........................        369,924              --
Deferred income taxes (note 5) .............................................         20,306              --
                                                                                  ---------       --------- 
                                                                                    409,325              --
                                                                                  ---------       --------- 
Commitments and contingencies (note 9) .....................................          3,700           3,700

Shareholders' equity (note 7)
  Preferred stock, par value $0.01 per share Authorized 10,000,000 shares,
    none issued
  Common stock, par value $0.01 per share Authorized 100,000,000 shares
    Issued 25,603,512 shares at December 31, 1997 and 1998 .................            256             256
  Additional paid-in capital ...............................................        137,812         137,812
  Retained earnings (deficit) ..............................................          4,035        (199,311)
                                                                                  ---------       ---------
      Total shareholders' equity ...........................................        142,103         (61,243)
                                                                                  ---------       ---------
                                                                                  $ 555,128       $ 350,068
                                                                                  =========       =========
</TABLE>

          SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




                                       36
<PAGE>   37

                               COHO ENERGY, INC.
                               AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
                                                                      YEAR ENDED DECEMBER 31
                                                               -------------------------------------- 
                                                                1996            1997           1998
                                                               ------          ------         ------
<S>                                                         <C>             <C>             <C>      
Operating revenues
 Crude oil and natural gas production (note 10) ........     $  54,272       $  63,130       $  68,759
                                                             ---------       ---------       ---------
Operating expenses
 Crude oil and natural gas production ..................        11,277          13,747          23,475
 Taxes on oil and gas production .......................         2,598           2,223           3,384
 General and administrative ............................         7,264           7,163           7,750
 Allowance for bad debt ................................            --              --             894
 Unsuccessful transaction costs ........................            --              --           2,129
 Depletion and depreciation ............................        16,280          19,214          28,135
 Writedown of crude oil and natural gas properties .....            --              --         188,000
                                                             ---------       ---------       ---------
     Total operating expenses ..........................        37,419          42,347         253,767
                                                             ---------       ---------       ---------
Operating income (loss) ................................        16,853          20,783        (185,008)
                                                             ---------       ---------       ---------

Other income and expenses ..............................         1,012             646             214
 Interest and other income .............................        (8,476)        (11,120)        (32,935)
                                                             ---------       ---------       ---------
 Interest expense ......................................        (7,464)        (10,474)        (32,721)
                                                             ---------       ---------       ---------
Earnings (loss) before income taxes ....................         9,389          10,309        (217,729)
                                                             ---------       ---------       ---------
Income taxes (note 5)
 Current (benefit) expense .............................          (411)            163           4,111
 Deferred (reduction) expense ..........................         3,894           3,858         (18,494)
                                                             ---------       ---------       ---------
                                                                 3,483           4,021         (14,383)
                                                             ---------       ---------       ---------
Net earnings (loss) ....................................     $   5,906       $   6,288       $(203,346)
                                                             =========       =========       =========
Basic earnings (loss) per common share .................     $     .29       $     .29       $   (7.94)
                                                             =========       =========       =========
Diluted earnings (loss) per common share ...............     $     .29       $     .28       $   (7.94)
                                                             =========       =========       =========
</TABLE>


          SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




                                       37
<PAGE>   38

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
                                                  NUMBER OF                 
                                                   COMMON                    ADDITIONAL     RETAINED
                                                    SHARES       COMMON       PAID-IN       EARNINGS
                                                 OUTSTANDING     STOCK        CAPITAL       (DEFICIT)         TOTAL
                                                 -----------     ------      ----------     ---------         -----
<S>                                              <C>           <C>           <C>           <C>           <C>
Balance at December 31, 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
  Issued on
    (i) Exercise of Employee Stock Options ...       256,386             3         1,733           --            1,736
    (ii) Public offering of common stock .....     5,000,000            50        49,173           --           49,223
    (iii) Warrants ...........................          --            --           3,390           --            3,390
  Net earnings ...............................          --            --            --            6,288          6,288
                                                 -----------   -----------   -----------    -----------    -----------
Balance at December 31, 1997 .................    25,603,512           256       137,812          4,035        142,103
  Net loss ...................................          --            --            --         (203,346)      (203,346)
                                                 -----------   -----------   -----------    -----------    -----------
Balance at December 31, 1998 .................    25,603,512   $       256   $   137,812    $  (199,311)   $   (61,243)
                                                 ===========   ===========   ===========    ===========    ===========
</TABLE>


           SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




                                       38
<PAGE>   39

                               COHO ENERGY, INC.
                                AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN THOUSANDS)


<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31
                                                                      --------------------------------
                                                                       1996         1997         1998
                                                                      ------       -------      ------  
<S>                                                                <C>          <C>             <C>
Cash flows from operating activities
 Net earnings (loss) ............................................   $   5,906    $   6,288    $(203,346)
Adjustments to reconcile net earnings to net cash provided 
 (used) by operating activities:
 Depletion and depreciation .....................................      16,280       19,214       28,135
 Writedown of crude oil and natural gas properties ..............        --           --        188,000
 Deferred income taxes ..........................................       3,894        3,858      (18,488)
 Amortization of debt issue costs and other .....................         271          591        1,756  
Changes in:
 Cash in escrow .................................................        --           --         (1,505)
 Accounts receivable ............................................      (6,983)       1,160       (1,150)
 Other assets ...................................................        (489)        (351)        (628)
 Accounts payable and accrued liabilities .......................          40        4,346        7,917
 Investment in marketable securities ............................      (1,512)       1,962         --
 Deferred income taxes and other current liabilities                     (560)        --           --
                                                                    ---------    ---------    ---------
Net cash provided by operating activities .......................      16,847       37,068          691
                                                                    ---------    ---------    ---------

Cash flows from investing activities
 Acquisitions ...................................................        --       (259,355)        --
 Property and equipment .........................................     (52,384)     (72,667)     (70,143)
 Changes in accounts payable and accrued liabilities related to
  exploration and development ...................................        (902)       3,559       (2,986)
 Proceeds on sale of property and equipment .....................      21,476         --         61,452
                                                                    ---------    ---------    ---------

Net cash used in investing activities ...........................     (31,810)    (328,463)     (11,677)
                                                                    ---------    ---------    ---------

Cash flows from financing activities
 Increase in long term debt .....................................      52,600      402,894       76,113
 Debt issuance costs ............................................        --         (4,275)        --
 Repayment of long term debt ....................................     (37,617)    (155,989)     (62,043)
 Proceeds from exercised stock options ..........................         414        1,495         --
 Issuance of common stock .......................................        --         49,223         --
                                                                    ---------    ---------    ---------

Net cash provided by financing activities .......................      15,397      293,348       14,070       
                                                                    ---------    ---------    ---------
Net increase in cash and cash equivalents .......................         434        1,953        3,084
Cash and cash equivalents at beginning of year ..................       1,430        1,864        3,817
                                                                    ---------    ---------    ---------
                                                                                     
Cash and cash equivalents at end of year ........................   $   1,864    $   3,817    $   6,901
                                                                    =========    =========    =========

Supplemental disclosure of cash flow information:
 Cash paid for interest .........................................   $   8,259    $   7,774    $  28,426
 Cash paid (received) for income taxes ..........................   $     478    $     603    $    (256)
</TABLE>


           SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




                                       39
<PAGE>   40

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
        (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

    Organization

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

    Principles of Presentation

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

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

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

    Cash Equivalents

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

    Cash in Escrow

       The cash in escrow will be released to the Company no later than April
1999. The amount released to the Company is subject to reduction pending
completion of the post closing review by the buyer of the Monroe field natural
gas properties, as discussed in Note 6. The Company does not anticipate any
significant reductions from this review.

    Accounts Receivable

       The Company performs ongoing reviews with respect to accounts receivable
and maintains an allowance for doubtful accounts receivable ($43,000 and
$929,000 at December 31, 1997 and 1998, respectively) based on expected
collectibility.

    Crude Oil and Natural Gas Properties

       The Company's crude oil and natural gas producing activities,
substantially all of which are in the United States, are accounted for using
the full cost method of accounting. Accordingly, the Company capitalizes all
costs incurred in connection with the acquisition of crude oil and natural gas
properties and with the exploration for and development of crude oil and
natural gas reserves, including related gathering facilities. 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.




                                       40
<PAGE>   41

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

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

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

   Impairment of Long-Lived Assets

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

   Other Assets

       Other assets generally include deferred financing charges which are
amortized over the term of the related financing under the straight line
method.

   Stock-Based Compensation

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

   Earnings Per Common Share

       The Company accounts for earnings per share ("EPS") in accordance with
SFAS No. 128 "Earnings Per Share." Under SFAS No. 128, no dilution for any
potentially dilutive securities is included for basic EPS. Diluted EPS 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 and warrants. Previously reported EPS were
equivalent to the diluted EPS calculated under SFAS No. 128.

<TABLE>
<CAPTION>
                                           1996                          1997                            1998
                                ---------------------------  -----------------------------     ---------------------------
                                            Common                        Common                           Common
                                 Income     Shares     EPS     Income     Shares      EPS       Loss       Shares     EPS
                                 ------     ------     ---     ------     ------      ---       ----       ------     ---
                                (in 000's)                    (in 000's)                                 (in 000's)
<S>                             <C>       <C>          <C>     <C>       <C>         <C>     <C>         <C>         <C>
BASIC EARNINGS PER SHARE         $ 5,906  20,178,917   $.29   $ 6,288   21,692,804   $.29   $(203,346)  25,603,512  $(7.94)
                                                       ====                          ====                           ======

Stock Options                                162,651                       641,099                           ---
                                 -------  ----------          -------   ----------          ---------   ----------

DILUTED EARNINGS PER SHARE       $ 5,906  20,341,568   $.29   $ 6,288   22,333,903   $.28   $(203,346)  25,603,512  $(7.94)
                                 =======  ==========   ====   =======   ==========   ====   =========   ==========  ======
</TABLE>




                                       41
<PAGE>   42

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


       Basic EPS were computed by dividing net income by the weighted average
number of shares of common stock outstanding during the year. Diluted EPS were
calculated based upon the weighted number of common shares outstanding during
the year including common stock equivalents, consisting of stock options for
the three years and warrants for 1997 and 1998, when their effect is dilutive.
In 1998, conversion of the stock options would have been anti-dilutive and,
therefore, was not considered in diluted EPS. In 1997 and 1998, conversion of
the warrants would have been anti-dilutive and, therefore, was not considered
in diluted EPS.

   Income Taxes

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

   Hedging Activities

       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.

  Environmental Expenditures

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

  Business Segments

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

2. FUTURE OPERATIONS

       The financial statements of the Company have been prepared on the basis
of accounting principles applicable to a going concern, which contemplates the
realization of assets and satisfaction of liabilities in the normal course of
business. Due to a continued period of depressed prices since December 1997,
the Company generated an operating loss of $185 million for the year ended
December 31, 1998, including a writedown of its oil and gas properties of $188
million. Although unaudited information subsequent to December 31, 1998
indicates that the Company should generate operating income during 1999,
assuming the Company does not experience further price or production
deterioration, the level of such operating income will not be sufficient to
cover interest accruing on its indebtedness or to meet other accrued
liabilities as they become due.




                                       42
<PAGE>   43

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


       Additionally, as discussed in Note 4, the Company received a notice of
default in March 1999 from its lenders under its existing bank credit facility
because the Company was unable to cure an over advance position of $89.6
million due to the reduction of its borrowing base as a result of the depressed
crude oil and natural gas prices. As a result of this bank default, the Company
may be in default under the terms of its 8 7/8% Senior Subordinated Notes
("Senior Notes") due to cross default provisions in the indenture related to
the Senior Notes. Although the lenders under the existing bank credit facility
have not accelerated the full amount outstanding of $235 million as of December
31, 1998 and although the Company may not be in default under the Senior Notes
indenture, all amounts outstanding under these facilities as of December 31,
1998 have been classified as current maturities because the Company is
currently unable to cure the existing or pending defaults within the required
terms of the related agreements.

       The Company is exploring its alternatives to resolve its current
liquidity problems, including (a) the current default under the existing bank
credit facility, (b) the potential acceleration of all amounts due under its
existing bank credit facility and the Senior Notes, and (c) inadequate cash flow
from operations to support upcoming interest payments due on the bank credit
facility on April 6, 1999 and on the Senior Notes due on April 15, 1999 or to
meet other accrued liabilities as they become due. The alternatives available to
the Company include, but are not limited to, the conversion of a portion or all
of the Senior Notes to equity, raising additional equity and/or refinancing the
Company's existing bank credit facility to make overdue principal and interest
payments on its indebtedness and to provide additional capital to fund repairs
on and the continued development of the Company's properties. The Company is
also evaluating cost reduction programs to enhance cash flow from operations.
There can be no assurance that the Company will be successful in resolving its
liquidity problems through the alternatives set forth above and may seek
protection under Chapter 11 of the United States Bankruptcy Code while pursuing
its other financing and/or reorganization alternatives. These factors, among
others, raise substantial doubt concerning the ability of the Company to
continue as a going concern.

       The financial statements do not include any adjustments relating to the
recoverability and classification of asset carrying amounts (including $324.6
million in net property, plant and equipment) or the amount and classification
of liabilities that might result should the Company be unable to continue as a
going concern. The ability of the Company to continue as a going concern is 
dependent upon raising additional equity and/or the refinancing of the 
Company's existing bank credit facility and the conversion of a portion or all 
of the Senior Notes to equity.

3. PROPERTY AND EQUIPMENT

<TABLE>
<CAPTION>
                                                                                              December 31
                                                                                         ---------------------
                                                                                           1997         1998
                                                                                         --------     --------
<S>                                                                                     <C>           <C>
   Crude oil and natural gas leases and rights including exploration,
       development and equipment thereon, at cost ...................................    $ 669,247    $ 678,547
   Accumulated depletion and depreciation ...........................................     (137,838)    (353,973)
                                                                                         ---------    ---------
                                                                                         $ 531,409    $ 324,574
                                                                                         =========    =========
</TABLE>

       Overhead expenditures directly associated with exploration for and
development of crude oil and natural gas reserves have been capitalized in
accordance with the accounting policies of the Company. Such charges totaled
$2,452,000, $4,081,000 and $5,749,000 in 1996, 1997 and 1998, respectively.

       During 1996, 1997 and 1998, the Company did not capitalize any interest
or other financing charges on funds borrowed to finance unproved properties or
major development projects.

       Unproved crude oil and natural gas properties totaling $82,872,000 and
$58,854,000 at December 31, 1997 and 1998, respectively, have been excluded
from costs subject to depletion. These costs are anticipated to be included in
costs subject to depletion within the next five years.

       Depletion and depreciation expense per equivalent barrel of production
was $4.55, $4.69 and $4.38 in 1996, 1997 and 1998, respectively.




                                       43
<PAGE>   44

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


4. LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                                                          1997         1998
                                                                                      -----------   -----------
<S>                                                                                     <C>          <C>
   Revolving credit facility ......................................................     $ 221,000    $ 235,000
   8 7/8% Senior Subordinated Notes Due 2007 ......................................       150,000      150,000
   Other ..........................................................................            68           24
                                                                                        ---------    ---------
                                                                                          371,068      385,024
   Unamortized original issue discount on senior subordinated notes ...............       (1,106)        (993)
   Current maturities on long term debt ...........................................          (38)    (384,031)
                                                                                        ---------    ---------
                                                                                        $ 369,924    $      --
                                                                                        =========    =========
</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 Agreement"), provided
a maximum commitment amount available to the Company ("Borrowing Base") of $242
million for general corporate purposes at December 31, 1998. Outstanding
advances as of December 31, 1998, were $235 million, and increased to $239.6
million as of January 5, 1999. The average effective interest rates for 1997
and 1998 were 7.37% and 7.38%, respectively. The Restated Credit Agreement,
which permits advances and repayments, terminates January 2, 2003. 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 up to $220 million bear
interest, at the option of the Company, at the bank prime rate or a Eurodollar
rate plus a maximum of 1.5% (currently 1.5%), with amounts outstanding in
excess of $220 million bearing interest, at the option of the Company at (i)
the prime rate plus 1.0% or (ii) LIBOR plus 2.50%. Loans under the Restated
Credit Agreement 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. If the outstanding amount of the loan exceeds the
Borrowing Base at any time, the Company is required to either (a) provide
collateral with value equal to such excess, (b) prepay, without premium or
penalty, such excess plus accrued interest or (c) 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.

       On February 22, 1999, the Company was informed by the lenders under the
Revolving Credit Facility that the Borrowing Base was reduced to $150 million
effective January 31, 1999 creating an over advance under the new Borrowing Base
of $89.6 million. The Company was unable to cure the over advance as required by
the Revolving Credit Facility by March 2, 1999. On March 8, 1999, the Company
received written notice from the lenders under the Revolving Credit Facility
that it was in default under the terms of the Revolving Credit Facility and the
lenders reserved all rights, remedies and privileges as a result of the payment
default. Additionally, as a result of the payment default, the past due balance
under the Revolving Credit Facility will bear interest at the default interest
rate of prime plus 4%. Although the lenders have not accelerated the full amount
outstanding under the Revolving Credit Facility, the outstanding advances of
$235 million as of December 31, 1998 have been reclassed to current maturities
because the Company is currently unable to cure the default within the required
terms. The Company is currently in discussions with the lenders under the
Revolving Credit Facility to work with the Company in restructuring this
repayment schedule so that the Company can continue to pursue alternative
arrangements.

       The Restated Credit Agreement contains certain financial and other
covenants including, among other covenants, (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 




                                       44
<PAGE>   45

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


additional debt, and (iv) restrictions on the payment of dividends. At December
31, 1998, the Company was not in compliance with the cash flow to interest
expense and current assets to current liabilities covenants.

 8 7/8% Senior Subordinated Notes

       On October 3, 1997, the Company completed a sale to the public of $150
million of 8 7/8% Senior Subordinated Notes due 2007 ("Senior Notes"). Proceeds
of the offering, net of offering costs, were approximately $144.5 million. The
proceeds from this offering, together with the proceeds from the common stock
offering discussed in Note 7, were used to repay indebtedness outstanding under
the Revolving Credit Facility and for general corporate purposes.

       The Senior Notes are unsecured senior subordinated obligations of the
Company and rank pari passu in right of payment with all existing and future
senior subordinated indebtedness of the Company. The Senior Notes mature on
October 15, 2007 and bear interest from October 3, 1997 at the rate of 8 7/8%
per annum payable semi-annually, commencing on April 15, 1998. Certain
subsidiaries of the Company issued guarantees of the Senior Notes on a senior
subordinated basis.

       The indenture issued in conjunction with the Senior Notes (the
"Indenture") contains certain covenants, including, among other covenants,
covenants that limit (i) indebtedness, (ii) restricted payments, (iii)
distributions from restricted subsidiaries, (iv) transactions with affiliates,
(v) sales of assets and subsidiary stock (including sale and leaseback
transactions), (vi) dividends and other payment restrictions affecting
restricted subsidiaries and (vii) mergers or consolidations.

       As a result of the payment default under the Revolving Credit Facility
discussed above, the Company may be in default under the terms of the Senior
Notes specified in the Indenture. If the Company is in default of the Senior
Notes as a result of the payment default under the Revolving Credit Facility,
the Company is required to deliver a written notice to the Trustee of the Senior
Notes within 30 days after the occurrence of the event of default in the form of
an officers' certificate indicating an event of default has occurred and is
continuing and what action the Company is taking or proposing to take with
respect to the event of default. Under an event of default of the Senior Notes,
the Trustee, by written notice to the Company, or the holders of at least 25% in
principal amount of the outstanding Senior Notes, may declare the principal and
accrued interest on all the Senior Notes due and payable immediately. However,
the Company may not pay the principal of, premium (if any) or interest on the
Senior Notes so long as any required payments due on the Revolving Credit
Facility remain outstanding and have not been cured or waived. All amounts
outstanding under the Senior Notes as of December 31, 1998 have been classified
as current maturities because the Company is currently unable to cure the
existing or pending default within the required terms of the Indenture.

 Debt Repayments

       Based on the balances outstanding and current default under the
Revolving Credit Facility and the Senior Notes indenture, estimated aggregate
principal repayments for each of the next five years are as follows: ; 1999 -
$385,016,000; 2000 - $8,000 and $0 thereafter.




                                       45
<PAGE>   46

                                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, 1997 and 1998, were as follows:

<TABLE>
<CAPTION>
                                                                                          1997        1998
                                                                                       ---------    --------
<S>                                                                                     <C>           <C>
   DEFERRED TAX ASSETS
       Net operating loss carryforwards .........................................       $ 25,176    $ 25,283
       Property and equipment, due to differences in depletion, depreciation,
           amortization and writedowns ..........................................           --        35,442
       Alternative minimum tax credit carryforwards .............................          1,095       1,467
       Employee benefits ........................................................            565          58
       Other ....................................................................            165         182
                                                                                        --------    --------
       Total gross deferred tax assets ..........................................         27,001      62,432
       Less valuation allowance .................................................         (4,594)    (62,432)
                                                                                        --------    --------
       Net deferred tax assets ..................................................         22,407        --
                                                                                        --------    --------
   DEFERRED TAX LIABILITIES
       Property and equipment, due to differences in depletion, depreciation,
           amortization and writedowns ..........................................         40,895        --
                                                                                        --------    --------
   NET DEFERRED TAX LIABILITY ...................................................       $ 18,488    $   --  
                                                                                        ========    ========
</TABLE>

       The valuation allowance for deferred tax assets as of December 31, 1997
and 1998 includes $2,051,000 related to Canadian deferred tax assets.

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

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

<TABLE>
<CAPTION>
                                                                      1996         1997         1998      
                                                                     ------       -------      ------     
<S>                                                                 <C>         <C>         <C>           
Earnings (loss) before income taxes ............................    $   9,389    $  10,309    $(217,729)  
                                                                    =========    =========    =========   
Expected income tax expense (recovery) (statutory rate - 34%)       $   3,192    $   3,505    $ (74,028)  
State taxes - deferred .........................................         (353)         552       (6,242)  
Federal benefit of state taxes .................................          120         (188)       2,122   
Expiring NOLs ..................................................         --           --          1,043   
Change in valuation allowance ..................................          471          444       57,838   
Other ..........................................................           53         (293)       4,884   
                                                                    ---------    ---------    ---------   
                                                                    $   3,483    $   4,020    $ (14,383)  
                                                                    =========    =========    =========   
</TABLE>




                                       46
<PAGE>   47

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


       At December 31, 1998, 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 ........................      1999      $ 1,727  
                                                                                                  2000        4,253  
                                                                                                  2001        3,015  
                                                                                                  2002          211  
                                                                                               2003-2018     52,090  
                                                                                                            $61,296  
   Operating loss carryforwards for Canadian income tax purposes ...........................   1999-2003    $ 3,573  
                                                                                                            =======  
   Operating loss carryforwards for federal alternative minimum tax                                                  
       purposes ............................................................................   2009-2010    $10,265  
                                                                                                            =======  
   Federal alternative minimum tax credit carryforwards ....................................      --        $ 1,467  
                                                                                                            =======  
   Operating loss carryforwards for Mississippi income tax purposes ........................   2010-2013    $50,938  
                                                                                                            =======  
   Operating loss carryforwards for Oklahoma income tax purposes ...........................   2012-2013    $16,652  
                                                                                                            =======  
</TABLE>

6. ACQUISITIONS AND DISPOSITIONS

       Effective December 31, 1997, the Company acquired from Amoco Production
Company ("Amoco") interests in certain crude oil and natural gas properties
("Oklahoma Properties") located primarily in southern Oklahoma for cash
consideration of approximately $257.5 million and warrants to purchase one
million shares of common stock at $10.425 per share for a period of five years
valued at $3.4 million. The Oklahoma Properties are in more than 25,000 gross
acres concentrated in southern Oklahoma, including 14 major producing oil
fields. The aggregate purchase price was $267.8 million, including transaction
costs of approximately $1.9 million and assumed liabilities of $5 million.
Investing activities in the cash flow statement for the year ended December 31,
1997 related to this acquisition, exclude the noncash portions of the purchase
price of $3.4 million attributable to the warrants and $5 million for assumed
liabilities.

       The following unaudited proforma information of the Company for the year
ended December 31, 1997 has been prepared assuming the acquisition of the
Oklahoma Properties occurred on January 1, 1997. Such proforma information is
not necessarily indicative of what actually could have occurred had the
acquisition taken place on January 1, 1997.

<TABLE>
<CAPTION>
                                                                   1997
                                                                 ---------
<S>                                                               <C>
Revenues .....................................................    $109,428
Net earnings .................................................       6,422
Basic earnings per share .....................................    $   0.30
Diluted earnings per share ...................................    $   0.29
</TABLE>

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



                                       47
<PAGE>   48

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


7. SHAREHOLDERS' EQUITY

       On October 3, 1997, the Company completed the sale to the public of
5,000,000 shares of common stock at $10.50 per share. Proceeds of the offering,
net of offering costs, were approximately $49.2 million. The proceeds from this
offering, together with the proceeds from the Senior Notes offering discussed
in Note 4, were used to repay indebtedness outstanding under the Company's
Revolving Credit Facility and for general corporate purposes.

       In December 1997, the Company issued warrants, valued at $3,390,000, to
purchase one million shares of common stock at $10.425 per share for a period
of five years to Amoco Production Company as partial consideration for the
purchase of certain crude oil and natural gas properties discussed in Note 6.

       In December 1996, the Company issued 100,000 shares of common stock,
valued at approximately $825,000, to Churchill Resource Investments Inc. as
consideration for the purchase of interest in certain crude oil properties.

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. Some exceptions have been
made to provide immediate or shortened vesting periods as approved by the
Company's board of directors. A summary of the status of the Company's stock
option plans at December 31, 1996, 1997 and 1998 and changes during the years
then ended follows:

<TABLE>
<CAPTION>
                                             1996                      1997                       1998
                                      ----------------------    ----------------------    ----------------------
                                                   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 .........    1,700,313    $   5.56     1,815,784    $   5.55      2,823,815    $   6.96     
    Granted ......................      202,000        5.19     1,286,000        8.73         14,000        6.88     
    Exercised ....................      (81,863)       5.05      (256,386)       5.82             --          --     
    Canceled .....................       (4,666)       5.43       (21,583)       6.50        (75,000)       8.90     
    Expired ......................           --          --            --          --       (131,555)       5.40     
                                      ---------    --------     ---------    --------      ---------    --------
Outstanding at December 31 .......    1,815,784        5.55     2,823,815        6.96      2,631,260        6.98     
                                      ---------    --------     ---------    --------      ---------    --------
Exercisable at December 31 .......    1,390,118        5.69     2,250,903        6.31      2,310,438        6.60     
Available for grant at
    December 31 ..................      118,836                    36,419                    189,919
</TABLE>




                                       48
<PAGE>   49

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


       Significant option groups outstanding at December 31, 1998 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>
May 12, 1998 ................              14,000                 --                   6.88         4
December 2, 1997 ............             371,000              123,679                10.50         6
August 22, 1997 .............              16,000                5,334                 9.38         6
May 12, 1997 ................               8,000                8,000                 8.13         4
March 3, 1997 ...............             809,000              773,500                 7.88         3
June 13, 1996 ...............              12,000               12,000                 6.63         3
February 22, 1996 ...........             150,000              150,000                 5.13         4
January 8, 1996 .............              40,000               26,666                 5.00         4
September 25, 1995 ..........              50,000               50,000                 5.00         3
September 12 ,1995 ..........              29,666               29,666                 5.00         4
August 3, 1995 ..............              24,000               24,000                 4.88         3
April 14, 1995 ..............              32,500               32,500                 5.00         3
December 4, 1994 ............             105,000              105,000                 5.01         4
November 10, 1994 ...........             240,000              240,000                 5.00         3
June 7, 1994 ................              79,883               79,883                 5.49         2
March 28, 1994 ..............               5,000                5,000                 4.50         1
October 22, 1993 ............             378,089              378,089                 6.00         2
September 29, 1993 ..........              93,378               93,378                 6.88         1
November 18, 1992 ...........               3,333                3,333                 5.25         1
October 19, 1992 ............             170,410              170,410                 5.67         1
</TABLE>

       The weighted average fair value of grant at date for options granted
during 1996, 1997 and 1998 was $2.21, $4.02 and $3.12 per option, respectively.
The fair value of options at date of grant was estimated using the
Black-Scholes model with the following weighted average assumptions:

<TABLE>
<CAPTION>
                                                  1996        1997       1998
                                                --------    --------   --------
<S>                                              <C>         <C>        <C>
Expected life (years) .........................       5           5          5
Interest rate .................................    5.37%       6.44%      5.67%
Volatility ....................................   38.79%      43.76%     42.01%
Dividend yield ................................      ---         ---        ---
</TABLE>




                                       49
<PAGE>   50

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


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

<TABLE>
<CAPTION>
                                                                                1996          1997          1998
                                                                              ---------     ---------     ---------
<S>                                                                           <C>             <C>        <C>
Net income (loss)                   As reported............................   $ 5,906        $ 6,288     $ (203,346)
                                      Pro forma............................   $ 5,625        $ 4,385     $ (204,108)
Basic earnings (loss) per share     As reported............................   $  0.29          $0.29     $    (7.94)
                                      Pro forma............................   $  0.27          $0.20     $    (7.97)
Diluted earnings (loss) per share   As reported............................   $  0.29          $0.28     $    (7.94)
                                      Pro forma............................   $  0.27          $0.20     $    (7.97)
</TABLE>

9. COMMITMENTS AND CONTINGENCIES

       (a) The Company, together with several other companies, has been named
as a defendant in a number of lawsuits in which the plaintiffs claim purported
damages caused by naturally occurring radioactive materials at various wellsite
locations on land leased by the Company in Mississippi. 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 1998, a suit was filed against the Company by the acquirer of the
Company's natural gas pipeline properties which were sold in 1996. This suit
alleges that the Company gave false and fraudulent information with regard to
the properties sold as well as alleging that the Company has interfered in
contracts and business relations subsequent to the sale. The plaintiff is
requesting payment for actual, punitive and other damages. The Company believes
these charges are without merit.

       In connection with the acquisition of the Oklahoma Properties on
December 18, 1997, the Company assumed the responsibility for costs and
expenses associated with the assessment, remediation, removal, transportation
and disposal of the asbestos or NORM associated with the Oklahoma Properties.
Additionally, the Company is responsible for all other environmental claims up
to approximately $10.3 million and all environmental claims not identified and
presented to Amoco by December 18, 1998. The Company is not currently aware of
any such claims and has concluded due diligence on environmental matters
associated with the acquisition.

       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. The Company has accrued $4.4 million, including $686,000
which has been reflected in current accrued liabilities, for future remediation
costs.

       (b) The Company has leased (i) 38,568 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, (iii) various vehicles under
non-cancellable leases extending through February 2000, and (iv) surface leases
in Laurel, Mississippi with expiration dates extending through the year 2018.
Rental expense totaled $1,081,000, $1,196,000 and $1,668,000 in 1996, 1997 and
1998, respectively. Minimum rentals payable under these leases for each of the
next five years are as follows: 1999 - $1,243,000; 2000 - $945,000; 2001 -
$162,000; 2002 - $158,000 and 2003 -$139,000. Total rentals payable over the
remaining terms of the leases are $4,711,000.




                                       50
<PAGE>   51

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


       (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 $6,000,000,
including the Oklahoma Properties. A total of $1,384,000 has been included in
depletion and depreciation expense with respect to such costs as of December
31, 1998.

       (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 $1.4
million.

       (e) The Company has entered into executive severance agreements with 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 $1.2 million.

       (f) In conjunction with the acquisition of the Oklahoma Properties, the
acquisition of ING and the 1993 reorganization, the Company has 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 4 occasions. The number of shares of Common Stock subject to
registration rights as of December 31, 1998, is approximately 3,324,000.

       (g) The Company is in the process of finalizing the location for an
exploratory well on its Anaguid permit in Tunisia, North Africa. A well must be
drilled by June 1999 or the acreage concession will expire. The Company's
estimated net cost to drill is approximately $2.5 million and the Company's net
carrying cost for its investment in the Anaguid permit is approximately $5.7
million as of December 31, 1998. If the Company is unable to drill this well by
June 1999 and the acreage concession expires, the Company will incur a liability
of approximately $4.0 million for unfulfilled commitments, of which $3.7 million
is due to the Tunisian government. Although the Company intends to drill this
well, the Company cannot currently predict whether it will have the financial
resources to make these expenditures.

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 $(5,908,000), $(232,000)
and $488,000 for 1996, 1997 and 1998, respectively, resulting from these
hedging programs. At December 31, 1997 and 1998, the Company had no deferred
hedging gains or losses. As of December 31, 1998, the Company had no crude oil
or natural gas hedged.

       Fair values of the Company's financial instruments are estimated through
a combination of management's estimates and by reference to quoted prices from
market sources and financial institutions, if available. As of December 31,
1998, the fair market value of the Company's Senior Notes was $57 million
compared to the related carrying value of $149 million. The fair value of the
Senior Notes approximated the related carrying value at December 31, 1997. The
carrying value of the Revolving Credit Facility approximated fair market value
at December 31, 1997 and 1998 since the applicable interest rate approximated
the market rate.



                                       51
<PAGE>   52

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


       During the years ended December 31, 1996 and 1997, EOTT Energy Corp.
("EOTT") accounted for 66% and 75%, respectively, of Coho's receipt of
operating revenues, and Mid Louisiana Marketing Company ("Midla Marketing"),
accounted for 15% and 21%, respectively, of Coho's receipt of operating
revenues. During the year ended December 31, 1998, EOTT, Midla Marketing and
Amoco Production Company accounted for 42%, 14% and 28%, respectively, of
Coho's receipt of operating revenues. Included in accounts receivable is
$7,222,491, $2,969,000 and $1,965,000 due from these customers at December 31,
1996, 1997 and 1998, respectively.

11. RELATED PARTY TRANSACTIONS

       (a) Corporations controlled by certain directors 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>
                                                                                   1996        1997
                                                                                  ------      ------
<S>                                                                                <C>         <C>
Campco International Capital Ltd. (i)
    Net crude oil and natural gas revenues.....................................     $243        $255
    Capital expenditures.......................................................      101         173
    Payable to (receivable from) CRI at the balance sheet date.................      (22)         16
</TABLE>
--------------

(i)    Campco International Capital Ltd. is a private company controlled by
       Frederick K. Campbell, a former director of the Company. Mr. Campbell
       resigned as a director in 1998.

       (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, 1998.

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

       (d) During 1996 and 1997, certain of the Company's hedging agreements
were with an affiliate of the Company, Morgan Stanley Capital Group, which
owned over 10% of the Company's outstanding common stock until October 3, 1997,
when its ownership dropped to 5.3% as a result of the equity offering discussed
in Note 6. Management of the Company believes that such transactions are on
similar terms as could be obtained from unrelated third parties. 




                                       52
<PAGE>   53

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


12. 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
                                                                            --------------------------------
                                                                             1996         1997         1998
                                                                            ------       ------       ------
<S>                                                                       <C>          <C>         <C>
Net earnings (loss) based on US GAAP ...................................   $   5,096    $   6,288    $(203,346)
Canadian writedown of oil and natural gas properties(ii)................        --           --       (109,000)
Adjustment to depletion based on difference in carrying value of oil
    and gas properties related to:
    ING acquisition(i) .................................................         556          562          483
    Business combination with Odyssey Exploration, Inc. in 1990 ........        (178)        (168)        (135)
    Application of Canadian full cost ceiling test .....................        (482)        (455)        (364)
Deferred tax effect of differences in US and Canadian GAAP .............          35           21       (4,790)
                                                                           ---------    ---------    ---------
Net earnings (loss) based on Canadian GAAP .............................   $   5,027    $   6,248    $(317,152)
                                                                           =========    =========    =========
Net earnings (loss) per common share based on Canadian GAAP ............   $    0.25    $    0.29    $  (12.39)
                                                                           =========    =========    =========
</TABLE>
------------------
(i)    Under SFAS No. 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. Under Canadian GAAP this adjustment is not
       required.

(ii)   Canadian GAAP requires a ceiling test to ensure that capitalized costs
       relating to oil and gas properties are recoverable in the future. The net
       book value of capitalized costs, less related deferred income taxes, is
       compared to the future net revenue plus the cost of major development
       projects and unproved properties, less future expenditures, which include
       removal and site restoration costs, income taxes, general and
       administrative costs and interest expense. General and administrative
       costs were calculated on a per barrel basis and calculated over the life
       of the reserves. Interest expense was calculated through the year 2013
       based on the Company's current debt at December 31, 1998, assuming all
       future positive cash flow from future net revenue, net of general and
       administrative costs, income taxes and interest expense, was used for
       retirement of existing debt.

       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, 1998
    Property and Equipment ............................................    $324,574    $(106,885)      $217,689
    Shareholder's Equity ..............................................    (61,243)    $(106,885)     (168,128)

DECEMBER 31, 1997
    Property and Equipment ............................................    $531,409        $2,131      $533,540
    Deferred Income Taxes .............................................      20,306       (4,790)        15,516
    Long Term Debt ....................................................     369,924       (1,106)       368,818
    Deferred Charges ..................................................         ---         1,106         1,106
    Shareholder's Equity ..............................................     142,103         6,921       149,024
</TABLE>




                                       53
<PAGE>   54

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


13. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)

<TABLE>
<CAPTION>
                                               First       Second        Third       Fourth        Total
                                              -------     --------      -------     --------      --------
<S>                                          <C>          <C>          <C>          <C>           <C>
1998
   Operating revenues ...................    $  21,143    $  18,147    $  16,539    $  12,930    $  68,759  
   Operating income .....................      (28,206)     (38,306)       1,344     (119,840)    (185,008) 
   Net earnings (loss) ..................      (22,301)     (41,611)      (7,168)    (132,266)    (203,346) 
   Basic earnings (loss) per share ......    $   (0.87)   $   (1.63)   $   (0.28)   $   (5.16)   $   (7.94) 
   Diluted earnings (loss) per share ....    $   (0.87)   $   (1.63)   $   (0.28)   $   (5.16)   $   (7.94) 

1997                                                                                                        
   Operating revenues ...................    $  15,536    $  13,985    $  15,985    $  17,624    $  63,130  
   Operating income .....................        5,604        4,151        4,990        6,038       20,783  
   Net earnings .........................        2,104        1,081        1,401        1,702        6,288  
   Basic earnings per share .............    $    0.10    $    0.05    $    0.07    $    0.07    $    0.29  
   Diluted earnings per share ...........    $    0.10    $    0.05    $    0.07    $    0.06    $    0.28  

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  
   Basic earnings per share .............    $    0.05    $    0.06    $    0.06    $    0.12    $    0.29  
   Diluted earnings per share ...........    $    0.05    $    0.06    $    0.06    $    0.12    $    0.29  
</TABLE>

     Basic per share figures are computed based on the weighted average number
of shares outstanding for each period shown. Diluted per share figures are
computed based on the weighted average number of shares outstanding including
common stock equivalents, consisting of stock options and warrants, when their
effect is dilutive.

14. SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS ACTIVITIES

  (a) COSTS INCURRED

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

<TABLE>
<CAPTION>
                                                                                1996         1997          1998
                                                                              ---------    ---------      --------
     <S>                                                                       <C>         <C>           <C>
     Property acquisitions
         Proved .........................................................     $   1,139    $ 199,485      $   8,432
         Unproved .......................................................           986       73,281          4,646
     Exploration ........................................................         6,528       13,374          5,061
     Development ........................................................        41,091       53,542         51,049
     Other ..............................................................           894          729            955
                                                                              ---------    ---------      ---------
     Property and equipment, net of accumulated depletion ...............     $  50,638    $ 340,411      $  70,143
                                                                              =========    =========      =========
                                                                              $ 210,212    $ 531,409      $ 324,574 
                                                                              =========    =========      =========
</TABLE>




                                       54
<PAGE>   55

                                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, 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
Revisions of previous estimates ..............      1,601       8,556
Purchase of reserves in place ................     49,723      32,581
Extensions and discoveries ...................     11,758         902
Production ...................................     (2,820)     (7,666)
                                                 --------    --------

Estimated reserves at December 31, 1997 ......     95,084     147,505
Revisions of previous estimates ..............     (7,645)      4,459
Purchase of reserves in place ................      6,842         480
Sales of reserves in place ...................       --       (94,106)
Extensions and discoveries ...................     10,792      16,114
Production ...................................     (5,069)     (8,124)
                                                 --------    --------
Estimated reserves at December 31, 1998 ......    100,004      66,328

Proved developed reserves at December 31,

 1996 ........................................     24,089      98,936
 1997 ........................................     62,663     129,392
 1998 ........................................     66,869      48,176
</TABLE>

  (c) Costs Incurred

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

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

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




                                       55
<PAGE>   56

                                COHO ENERGY, INC.
                                AND SUBSIDIARIES

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)


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

<TABLE>
<CAPTION>
                                                                     1996           1997           1998
                                                                 -----------    -----------    -----------
<S>                                                             <C>            <C>             <C>       
Future cash inflows ..........................................   $ 1,174,356    $ 1,764,924    $ 1,081,003
Future production costs ......................................      (301,619)      (607,114)      (419,820)
Future development costs .....................................       (52,769)      (114,294)      (112,165)
                                                                 -----------    -----------    -----------
Future net cash flows before income taxes ....................       819,968      1,043,516        549,018
Annual discount at 10% .......................................      (402,885)      (517,239)      (279,720)
                                                                 -----------    -----------    -----------
Present value of future net cash flows before income taxes
   ("Present Value of Proved Reserves") ......................       417,083        526,277        269,298
Future income taxes discounted at 10% ........................       (79,864)       (58,084)            --
                                                                 -----------    -----------    -----------
Standardized measure of discounted future net cash flows .....   $   337,219    $   468,193    $   269,298
                                                                 ===========    ===========    ===========
West Texas Intermediate posted reference price ($ per Bbl) ...   $     25.25    $     16.17    $      9.50
Estimated December 31 Company average realized price
   $/Bbl .....................................................   $     22.02    $     15.06    $      9.36
   $/Mcf .....................................................   $      3.53    $      2.26    $      2.10
</TABLE>

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


<TABLE>
<CAPTION>
                                                                  1996          1997        1998
                                                               -----------  -----------  -----------
<S>                                                            <C>           <C>         <C>       
Crude oil and natural gas sales, net of production costs ....   $ (46,305)   $ (47,392)   $ (41,412)
Net changes in anticipated prices and production costs ......     128,960     (176,309)    (184,445)
Extensions and discoveries, less related costs ..............      74,560       73,565       39,510
Changes in estimated future development costs ...............      (2,580)      (6,393)        (905)
Development costs incurred during the period ................       6,321       10,817       22,040
Net change due to sales and purchase of reserves in place ...       1,108      224,579      (53,534)
Accretion of discount .......................................      26,862       41,708       52,628
Revision of previous quantity estimates .....................      (1,643)      11,737      (20,178)
Net changes in income taxes .................................     (36,185)      21,780       58,084
Changes in timing of production and other ...................     (38,818)     (23,118)     (70,683)
                                                                ---------    ---------    ---------  

Net increase (decrease) .....................................     112,280      130,974     (198,895)
Beginning of year ...........................................     224,939      337,219      468,193
                                                                ---------    ---------    ---------  
Standardized measure of discounted future net cash flows ...    $ 337,219    $ 468,193    $ 269,298
                                                                =========    =========    =========
</TABLE>



                                       56
<PAGE>   57

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 is expected to appear under the
captions "Election of Directors" and "Executive Officers" in the Company's
proxy statement for the Annual Meeting of Shareholders to be held in 1999 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 is expected to appear under the
caption "Executive Compensation" set forth in the Company's proxy statement for
the Annual Meeting of Shareholders to be held in 1999 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 is expected to appear 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 held in 1999 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 is expected to appear under the
caption "Certain Relationships and Related Transactions" set forth in the
Company's proxy statement for the Annual Meeting of Shareholders to be held in
1999 to be filed with the Securities and Exchange Commission pursuant to
Regulation 14A, which information is incorporated herein by reference.



                                       57
<PAGE>   58

                                    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 34.

2.     FINANCIAL STATEMENT SCHEDULES

<TABLE>
<CAPTION>
                                                                           PAGE
                                                                           ----
      <S>                                                                   <C>
       Report of Independent Public Accountants ........................... 62
       Schedule III -- Condensed Financial Information - Parent Only ...... 63
</TABLE>

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

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

         4.2      -    Bylaws of the Company (included as Exhibit 3(ii).1
                       above).

         4.3      -    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).

         4.4      -    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).

         4.5      -    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).

         4.6      -    Third Amendment to Rights Agreement as of August 19, 1998
                       between Coho Energy, Inc. and Chase Manhattan Bank.

         4.7      -    Indenture dated as of October 1, 1997 for the 8 7/8%
                       Senior Subordinated Notes due 2007 (incorporated by
                       reference to Exhibit 4.7 to the Company's Second
                       Amendment dated September 9, 1997 to its Registration
                       Statement on Form S-3 (Registration No. 333-33979)).

         4.8      -    First Supplemental Indenture dated as of September 2,
                       1998 for the 8 7/8% Senior Subordinated Notes due 2007.
</TABLE>



                                       58
<PAGE>   59

<TABLE>
       <S>             <C>
        10.1      -    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).

       *10.2      -    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)).

       *10.3      -    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).

       *10.4      -    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).

       *10.5      -    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).

       *10.6      -    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).

       *10.7      -    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).

       *10.8      -    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).

       *10.9      -    Employment Agreement dated as of August 19, 1996 by and
                       between Anne Marie O'Gorman and Coho Energy, Inc.
                       (incorporated by reference to Exhibit 10.10 to the
                       Company's Annual Report on Form 10-K for the year ended
                       December 31, 1996).

       *10.10     -    First Amendment to Employment Agreement dated as of
                       August 19, 1996 by and among Jeffrey Clarke and Coho
                       Energy, Inc. (incorporated by reference to Exhibit 10.11
                       to the Company's Annual Report on Form 10-K for the year
                       ended December 31, 1996).

       *10.11     -    First Amendment to Employment Agreement dated as of
                       August 19, 1996 by and among R. M. Pearce and Coho
                       Energy, Inc. (incorporated by reference to Exhibit 10.12
                       to the Company's Annual Report on Form 10-K for the year
                       ended December 31, 1996).

       *10.12     -    First Amendment to Employment Agreement dated as of
                       August 19, 1996 by and among Eddie M. LeBlanc and Coho
                       Energy, Inc. (incorporated by reference to Exhibit 10.13
                       to the Company's Annual Report on Form 10-K for the year
                       ended December 31, 1996).

       *10.13     -    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)).

       *10.14     -    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).

       *10.15     -    Form of Executive Severance Agreement entered into with
                       each of Keri Clarke, R. Lynn Guillory, Larry L. Keller,
                       Susan J. McAden, Joseph Ragusa, Gary Hoge 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).
</TABLE>




                                       59
<PAGE>   60

<TABLE>
       <S>             <C>
       *10.16     -    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.

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

        10.18     -    Fourth Amended and Restated Credit Agreement among Coho
                       Resources, Inc., Coho Louisiana Production Company, Coho
                       Exploration, Inc., Coho Acquisitions Company, Coho
                       Energy, Inc., Banque Paribas, Houston Agency, Bank One,
                       Texas, N.A., and Meespierson N.V. dated as of December
                       18, 1997 (incorporated by reference to Exhibit 10.23 to
                       the Company's Annual Report on Form 10-K for the year
                       ended December 31, 1997).

        10.19     -    First Amendment to the Fourth Amended and Restated Credit
                       Agreement dated July 7, 1998 among Coho Resources, Inc.,
                       Coho Louisiana Production Company, Coho Exploration,
                       Inc., Coho Oil & Gas, Inc. (formerly Coho Acquisitions
                       Company), Coho Energy, Inc., Banque Paribas, Houston
                       Agency, Bank One, Texas, N.A., and MeesPierson N.V.

        10.20     -    Second Amendment to the Fourth Amended and Restated
                       Credit Agreement dated November 13, 1998 among Coho
                       Resources, Inc., Coho Louisiana Production Company, Coho
                       Exploration, Inc., Coho Oil & Gas, Inc. (formerly Coho
                       Acquisitions Company), Coho Energy, Inc., Banque Paribas,
                       Houston Agency, Bank One, Texas, N.A., and MeesPierson
                       N.V.

        10.21     -    Third Amendment to the Fourth Amended and Restated Credit
                       Agreement dated November 30, 1998 among Coho Resources,
                       Inc., Coho Louisiana Production Company, Coho
                       Exploration, Inc., Coho Oil & Gas, Inc. (formerly Coho
                       Acquisitions Company), Coho Energy, Inc., Banque Paribas,
                       Houston Agency, Bank One, Texas, N.A., and MeesPierson
                       N.V.

        10.22     -    Fourth Amendment to the Fourth Amended and Restated
                       Credit Agreement dated January 29, 1999 among Coho
                       Resources, Inc., Coho Louisiana Production Company, Coho
                       Exploration, Inc., Coho Oil & Gas, Inc. (formerly Coho
                       Acquisitions Company), Coho Energy, Inc., Banque Paribas,
                       Houston Agency, Bank One, Texas, N.A., and MeesPierson
                       N.V.

        10.23     -    Crude Call Purchase Contract dated November 26, 1997 by
                       and between Amoco Production Company and Coho
                       Acquisitions Company (incorporated by reference to
                       Exhibit 2.1 to the Company's Report on Form 8-K dated
                       December 18, 1997).

        10.24     -    Purchase and Sale Agreement dated November 26, 1997 by
                       and between Amoco Production Company and Coho
                       Acquisitions Company (incorporated by reference to
                       Exhibit 2.1 to the Company's Report on Form 8-K dated
                       December 31,1997).

        10.25     -    Shareholder Agreement (incorporated by reference to Item
                       7(1) of the Exhibits to the Schedule 13D dated May 18,
                       1998, relating to the Company and filed by Energy
                       Investment Partnership No. 1, Thomas O. Hicks, John R.
                       Muse, Charles W. Tate, Jack D. Furst, Lawrence D. Stuart,
                       Jr., Michael J. Levitt, Dan H. Blanks, and David B.
                       Deniger).

        10.26     -    Amended and Restated Stock Purchase Agreement dated
                       November 4, 1998, by and between Coho Energy, Inc. and
                       HM4 Coho, L.P. (incorporated by reference to Exhibit 99.1
                       to the Report on Form 8-K dated November 18, 1998).

       *10.27     -    Adoption Agreement for Coho Resources, Inc.'s Amended and
                       Restated 401(k) Savings Plan dated July 1, 1995.

        11.1      -    Statement re-computation of per share earnings.

        21.1      -    List of Subsidiaries of the Company.

        27        -    Financial Data Schedule
</TABLE>

-------------------
*  Represents management contract or compensatory plan or arrangement.





                                       60
<PAGE>   61

       The Company will furnish a copy of any exhibit described above to any
beneficial holder of its securities upon receipt of a written request therefor,
provided that such request sets forth a good faith representation that as of
the record date for the Company's 1999 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

       Form 8-K dated November 18, 1998 regarding changes of control of the
registrant related to the issuance of shares of Common Stock to HM4 Coho L.P.




                                       61
<PAGE>   62

                   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.

       The basic financial statements have been prepared assuming that Coho
Energy, Inc. and subsidiaries will continue as a going concern. As discussed in
Note 2 to the basic financial statements, Coho Energy, Inc. and subsidiaries
have suffered recurring losses, have received a notice of default from their
lenders under the existing bank credit facility and may be in default under the
terms of the 8 7/8% Senior Subordinated notes, and project negative cash flow
from operations in 1999 that raise substantial doubt about the Company's ability
to continue as a going concern. Management's plans in regard to these matters
are also described in Note 2. The financial statements do not include any
adjustments relating to the recoverability and classification of asset carrying
amounts or the amount and classification of liabilities that might result should
the Company be unable to continue as a going concern.

                                                           Arthur Andersen LLP


Dallas, Texas
March 24, 1999




                                       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,
1997 and 1998 and statements of operations and statements of cash flows for
Coho Energy, Inc., the parent company, for the years ended December 31, 1996,
1997 and 1998.

                                COHO ENERGY, INC.
                                    (PARENT)

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

                                     ASSETS

<TABLE>
<CAPTION>
                                                                     DECEMBER 31 
                                                               ----------------------
                                                                 1997          1998
                                                               --------      --------
<S>                                                           <C>           <C>
Current assets
  Cash and cash equivalents ................................   $      27    $       6
  Due from subsidiaries ....................................     180,743      158,913
                                                               ---------    ---------
                                                                 180,770      158,919
Investments in subsidiaries, at equity .....................     109,247      (72,179)
Other assets
                                                                   4,297        3,871
                                                               ---------    ---------
                                                               $ 294,314    $  90,611
                                                               =========    =========
                      LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
  Accounts payable .........................................   $   3,317    $   2,847
  Current portion of long-term debt ........................     148,894      149,007
                                                               ---------    ---------
                                                                 152,211      151,854
                                                               ---------    ---------
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 100,000,000 shares
      Issued 25,603,512 shares at December 31, 1997 and 
      1998 .................................................
  Additional paid-in capital ...............................         256          256
Retained earnings (deficit) ................................     137,812      137,812
      Total shareholders' equity ...........................       4,035     (199,311)
                                                               ---------    ---------
                                                                 142,103      (61,243)
                                                               ---------    ---------
                                                               $ 294,314    $  90,611
                                                               =========    =========
</TABLE>


           See accompanying Notes to Condensed Financial Information




                                       63
<PAGE>   64

                                                                  SCHEDULE III

                                COHO ENERGY, INC.
                                    (PARENT)

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


<TABLE>
<CAPTION>
                                                              December 31
                                                 --------------------------------------
                                                    1996         1997         1998
                                                 -----------  -----------  -----------
<S>                                              <C>            <C>             <C>
Operating expenses
  General and administrative ..................   $     423    $     471    $     666
                                                  ---------    ---------    ---------
Other (income) expenses
  Interest income from subsidiaries ...........          --       (4,320)     (14,519)
  Interest expense ............................          --        3,389       13,864
  Equity in (income) loss of subsidiaries .....      (6,329)      (5,828)     203,326
                                                  ---------    ---------    ---------
                                                     (6,329)      (6,759)     202,671
                                                  ---------    ---------    ---------
Earnings (loss) before income taxes ...........       5,906        6,288     (203,337)

Income taxes
  Deferred expense ............................          --           --            9

Net earnings (loss) ...........................   $   5,906    $   6,288    $(203,346)
                                                  =========    =========    =========
Basic earnings (loss)per common share .........   $     .29    $     .29    $   (7.94)
                                                  =========    =========    =========
Diluted earnings (loss) per common share ......   $     .29    $     .28    $   (7.94)
                                                  =========    =========    =========
</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
                                                                          -------------------------------------- 
                                                                              1996         1997         1998
                                                                          -----------  -----------  -----------  
<S>                                                                         <C>            <C>             <C>
Cash flows from operating activities
  Net earnings (loss) .................................................   $   5,906    $   6,288    $(203,346)
Adjustments to reconcile net earnings (loss) to net cash provided
  by operating activities:
  Equity in loss (income) of subsidiaries .............................      (6,329)      (5,828)     203,346
  Amortization of debt issue costs and other ..........................        --           --            552
  Deferred income taxes ...............................................        --           --              9
Changes in:
  Other assets ........................................................        --            (22)         (12)
  Accounts payable ....................................................         (15)       3,312         (480)
                                                                          ---------    ---------    ---------

Net cash provided by (used in) operating activities ...................        (438)       3,750           49
                                                                          ---------    ---------    ---------
Cash flows from investing activities
  Investments in subsidiaries .........................................        --        (26,397)     (21,900)
  Advances from (to) subsidiaries .....................................         325     (172,967)      21,830
                                                                          ---------    ---------    ---------
Net cash provided by (used in) investing activities ...................         325     (199,364)         (70)
                                                                          ---------    ---------    ---------

Cash flows from financing activities
  Increase in long term debt ..........................................        --        148,894         --
  Debt issuance cost ..................................................        --         (4,275)        --
  Issuance of common stock ............................................        --         49,223         --
  Proceeds from stock options exercised                                         414        1,495         --
                                                                          ---------    ---------    ---------
Net cash provided by (used in) financing activities ...................         414      195,337         --
                                                                          ---------    ---------    ---------
Increase (decrease) in cash ...........................................         301         (277)         (21)
Cash and cash equivalents at beginning of period ......................           3          304           27
                                                                          ---------    ---------    ---------
Cash and cash equivalents at end of period ............................   $     304    $      27    $       6
                                                                          =========    =========    =========
</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, 1996, 1997 AND 1998

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, 1998.

2.     FUTURE OPERATIONS

       The financial statements of the Company have been prepared on the basis
of accounting principles applicable to a going concern, which contemplates the
realization of assets and satisfaction of liabilities in the normal course of
business. Due to a continued period of depressed prices since December 1997,
the Company generated a loss before income taxes of $203.3 million for the year
ended December 31, 1998 primarily due to the equity in loss of subsidiaries of
$203.3 million.

       As discussed in Note 3, the Company has guaranteed $235 million of debt
related to unconsolidated subsidiaries under the Revolving Credit Facility. In
March 1999, such subsidiaries received a notice of default from the lenders
under the Revolving Credit Facility because they were unable to cure an over
advance position of $89.6 million due to the reduction of its borrowing base as
a result of the depressed crude oil and natural gas prices. As a result of this
bank default, the Company may be in default under the terms of its 8 7/8% Senior
Subordinated Notes ("Senior Notes") due to cross default provisions in the
indenture. Although the Company may not be in default under the Senior Notes
indenture, all amounts outstanding under the Senior Notes as of December 31,
1998 have been classified as current maturities because the Company and its
unconsolidated subsidiaries are currently unable to cure the existing or pending
defaults within the required terms of the indenture.

       The Company is exploring its alternatives to resolve its current
liquidity problems and the liquidity problems of its unconsolidated
subsidiaries, including (a) the current default under the existing bank credit
facility, (b) the potential acceleration of all amounts due under the existing
bank credit facility and the Senior Notes, (c) inadequate cash flow from
operations to support upcoming interest payments due on the credit facility on
April 6, 1999 and on the Senior Notes due on April 15, 1999 or to meet other
accrued liabilities as they become due. The alternatives available to the
Company include, but are not limited to, the conversion of a portion or all of
the Senior Notes to equity, raising additional equity and/or refinancing the
Company's existing bank credit facility to make overdue principal and interest
payments on its indebtedness and to provide additional capital to fund repairs
on and the continued development of the Company's properties. The Company is
also evaluating cost reduction programs to enhance cash flow from operations of
its unconsolidated subsidiaries. There can be no assurance that the Company will
be successful in resolving its liquidity problems through the alternatives set
forth above and may seek protection under Chapter 11 of the United States
Bankruptcy Code while pursuing its other financing and/or reorganization
alternatives. These factors, among others, raise substantial doubt concerning
the ability of the Company to continue as a going concern.

       The financial statements do not include any adjustments relating to the
recoverability and classification of asset carrying amounts or the amount and
classification of liabilities that might result should the Company be unable to
continue as a going concern. The ability of the Company to continue as a going 
concern is dependent upon raising additional equity and/or the refinancing of 
the Company's existing bank credit facility and the conversion of a portion or 
all of the Senior Notes to equity.

3.     COMMITMENTS AND CONTINGENCIES

       The Company has guaranteed $235 million of debt related to
unconsolidated subsidiaries under the Revolving Credit Facility. Currently, the
subsidiaries are in default on such debt as discussed in Note 4 to the
Consolidated Financial Statements of the Company.




                                       66
<PAGE>   67

       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. At December 31, 1998, the Company was not in compliance with the
cash flow to interest expense and current assets to current liabilities
covenants.

4.     LONG TERM DEBT

       On October 3, 1997, the Company completed a sale to the public of $150
million of 8 7/8% Senior Subordinated Notes due 2007 ("Senior Notes"). Proceeds
of the offering, net of offering costs, were approximately $144.5 million. The
proceeds from this offering, together with the proceeds from the common stock
offering discussed in Note 5, were used to repay indebtedness outstanding under
the Revolving Credit Facility and for general corporate purposes.

       The Senior Notes are unsecured senior subordinated obligations of the
Company and rank pari passu in right of payment with all existing and future
senior subordinated indebtedness of the Company. The Senior Notes mature on
October 15, 2007 and bear interest at the rate of 8 7/8% per annum payable
semi-annually. Certain subsidiaries of the Company issued guarantees of the
Senior Notes on a senior subordinated basis. 

       The indenture issued in conjunction with the Senior Notes (the
"Indenture") contains certain covenants, including covenants that limit (i)
indebtedness, (ii) restricted payments, (iii) distributions from restricted
subsidiaries, (iv) transactions with affiliates, (v) sales of assets and
subsidiary stock (including sale and leaseback transactions), (vi) dividends and
other payment restrictions affecting restricted subsidiaries and (vii) mergers
or consolidations.

       As a result of the payment default under the Revolving Credit Facility as
discussed in Note 4 to the Consolidated Financial Statements of the Company, the
Company may be in default under the terms of the Senior Notes specified in the
Indenture. If the Company is in default of the Senior Notes as a result of the
payment default under the Revolving Credit Facility, the Company is required to
deliver a written notice to the Trustee of the Senior Notes within 30 days after
the occurrence of the event of default in the form of an officers' certificate
indicating an event of default has occurred and is continuing and what action
the Company is taking or proposing to take with respect to the event of default.
Under an event of default of the Senior Notes, the Trustee by written notice to
the Company, or the holders of at least 25% in principal amount of the
outstanding Senior Notes may declare the principal and accrued interest on all
the Senior Notes due and payable immediately. However, the Company may not pay
the principal of, premium (if any) or interest on the Senior Notes so long as
any required payments due on the Revolving Credit Facility remain outstanding
and have not been cured or waived. All amounts outstanding under the Senior
Notes as of December 31, 1998 have been classified as current maturities
because the Company is currently unable to cure the existing or pending default
within the required terms of the Indenture.
      
5.     SHAREHOLDERS' EQUITY

       On October 3, 1997, the Company completed the sale to the public of
5,000,000 shares of common stock at $10.50 per share. Proceeds of the offering,
net of offering costs, were approximately $49.2 million. The proceeds from this
offering, together with the proceeds from the Senior Notes offering discussed
in Note 3, were used to repay indebtedness outstanding under the Company's
Revolving Credit Facility and for general corporate purposes.

       In December 1997, the Company issued warrants, valued at $3.4 million,
to purchase one million shares of common stock at $10.425 per share for a
period of five years to Amoco Production Company as partial consideration for
the purchase of certain crude oil and natural gas properties. This noncash
transaction is not reflected in the statement of cash flows for the year ended
December 31, 1998.



                                       67
<PAGE>   68

                                   SIGNATURES

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

                                       Coho Energy, Inc.

Date: March 31, 1999                   By: /s/ JEFFREY CLARKE
      --------                             ------------------------------
                                               Jeffrey Clarke
                                               Chairman, President and Chief 
                                               Executive Officer

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

<TABLE>
<CAPTION>
                Signature                                     Title                        Date
                ---------                                     -----                        ----
<S>                                                  <C>                                  <C>
/s/ JEFFREY CLARKE                                      Chairman, President               March 31, 1999
------------------------------------------            Chief Executive Officer
Jeffrey Clarke                                            and Director


/s/ EDDIE M. LEBLANC, III                               Sr. Vice President and            March 31, 1999
------------------------------------------             Chief Financial Officer
Eddie M. LeBlanc, III                                   (principal financial
                                                       and accounting officer)

/s/ LOUIS F. CRANE                                       Director                         March 31, 1999
-----------------------------------------
Louis F. Crane

/s/ ALAN EDGAR                                           Director                         March 31, 1999
-----------------------------------------
Alan Edgar

/s/  KENNETH H. LAMBERT                                  Director                         March 31, 1999
-----------------------------------------
Kenneth H. Lambert

/s/ DOUGLAS R. MARTIN                                    Director                         March 31, 1999
-----------------------------------------
Douglas R. Martin

/s/ JAKE TAYLOR                                          Director                         March 31, 1999
-----------------------------------------
Jake Taylor
</TABLE>




                                       68
<PAGE>   69

                               INDEX TO EXHIBITS

<TABLE>
<CAPTION>
EXHIBIT 
NUMBER              DESCRIPTION
--------            -----------
        <S>           <C>
         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(ii).1  -    Bylaws of the Company, (incorporated by reference to
                       Exhibit 3.2 to the Company's Registration Statement on
                       Form S-4 (Registration No. 33-65620)).

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

         4.2      -    Bylaws of the Company (included as Exhibit 3(ii).1
                       above).

         4.3      -    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).

         4.4      -    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).

         4.5      -    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).

         4.6      -    Third Amendment to Rights Agreement as of August 19, 1998
                       between Coho Energy, Inc. and Chase Manhattan Bank.

         4.7      -    Indenture dated as of October 1, 1997 for the 8 f% Senior
                       Subordinated Notes due 2007 (incorporated by reference to
                       Exhibit 4.7 to the Company's Second Amendment dated
                       September 9, 1997 to its Registration Statement on Form
                       S-3 (Registration No. 333-33979)).

         4.8      -    First Supplemental Indenture dated as of September 2,
                       1998 for the 8 f% Senior Subordinated Notes due 2007.
</TABLE>



                                       69
<PAGE>   70

<TABLE>
       <S>             <C>
        10.1      -    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).

       *10.2      -    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)).

       *10.3      -    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).

       *10.4      -    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).

       *10.5      -    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).

       *10.6      -    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).

       *10.7      -    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).

       *10.8      -    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).

       *10.9      -    Employment Agreement dated as of August 19, 1996 by and
                       between Anne Marie O'Gorman and Coho Energy, Inc.
                       (incorporated by reference to Exhibit 10.10 to the
                       Company's Annual Report on Form 10-K for the year ended
                       December 31, 1996).

       *10.10     -    First Amendment to Employment Agreement dated as of
                       August 19, 1996 by and among Jeffrey Clarke and Coho
                       Energy, Inc. (incorporated by reference to Exhibit 10.11
                       to the Company's Annual Report on Form 10-K for the year
                       ended December 31, 1996).

       *10.11     -    First Amendment to Employment Agreement dated as of
                       August 19, 1996 by and among R. M. Pearce and Coho
                       Energy, Inc. (incorporated by reference to Exhibit 10.12
                       to the Company's Annual Report on Form 10-K for the year
                       ended December 31, 1996).

       *10.12     -    First Amendment to Employment Agreement dated as of
                       August 19, 1996 by and among Eddie M. LeBlanc and Coho
                       Energy, Inc. (incorporated by reference to Exhibit 10.13
                       to the Company's Annual Report on Form 10-K for the year
                       ended December 31, 1996).

       *10.13     -    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)).

       *10.14     -    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).

       *10.15     -    Form of Executive Severance Agreement entered into with
                       each of Keri Clarke, R. Lynn Guillory, Larry L. Keller,
                       Susan J. McAden, Joseph Ragusa, Gary Hoge 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).
</TABLE>


                                       70
<PAGE>   71

<TABLE>
       <S>             <C>
       *10.16     -    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.

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

        10.18     -    Fourth Amended and Restated Credit Agreement among Coho
                       Resources, Inc., Coho Louisiana Production Company, Coho
                       Exploration, Inc., Coho Acquisitions Company, Coho
                       Energy, Inc., Banque Paribas, Houston Agency, Bank One,
                       Texas, N.A., and Meespierson N.V. dated as of December
                       18, 1997 (incorporated by reference to Exhibit 10.23 to
                       the Company's Annual Report on Form 10-K for the year
                       ended December 31, 1997).

        10.19     -    First Amendment to the Fourth Amended and Restated Credit
                       Agreement dated July 7, 1998 among Coho Resources, Inc.,
                       Coho Louisiana Production Company, Coho Exploration,
                       Inc., Coho Oil & Gas, Inc. (formerly Coho Acquisitions
                       Company), Coho Energy, Inc., Banque Paribas, Houston
                       Agency, Bank One, Texas, N.A., and MeesPierson N.V.

        10.20     -    Second Amendment to the Fourth Amended and Restated
                       Credit Agreement dated November 13, 1998 among Coho
                       Resources, Inc., Coho Louisiana Production Company, Coho
                       Exploration, Inc., Coho Oil & Gas, Inc. (formerly Coho
                       Acquisitions Company), Coho Energy, Inc., Banque Paribas,
                       Houston Agency, Bank One, Texas, N.A., and MeesPierson
                       N.V.

        10.21     -    Third Amendment to the Fourth Amended and Restated Credit
                       Agreement dated November 30, 1998 among Coho Resources,
                       Inc., Coho Louisiana Production Company, Coho
                       Exploration, Inc., Coho Oil & Gas, Inc. (formerly Coho
                       Acquisitions Company), Coho Energy, Inc., Banque Paribas,
                       Houston Agency, Bank One, Texas, N.A., and MeesPierson
                       N.V.

        10.22     -    Fourth Amendment to the Fourth Amended and Restated
                       Credit Agreement dated January 29, 1999 among Coho
                       Resources, Inc., Coho Louisiana Production Company, Coho
                       Exploration, Inc., Coho Oil & Gas, Inc. (formerly Coho
                       Acquisitions Company), Coho Energy, Inc., Banque Paribas,
                       Houston Agency, Bank One, Texas, N.A., and MeesPierson
                       N.V.

        10.23     -    Crude Call Purchase Contract dated November 26, 1997 by
                       and between Amoco Production Company and Coho
                       Acquisitions Company (incorporated by reference to
                       Exhibit 2.1 to the Company's Report on Form 8-K dated
                       December 18, 1997).

        10.24     -    Purchase and Sale Agreement dated November 26, 1997 by
                       and between Amoco Production Company and Coho
                       Acquisitions Company (incorporated by reference to
                       Exhibit 2.1 to the Company's Report on Form 8-K dated
                       December 31,1997).

        10.25     -    Shareholder Agreement (incorporated by reference to Item
                       7(1) of the Exhibits to the Schedule 13D dated May 18,
                       1998, relating to the Company and filed by Energy
                       Investment Partnership No. 1, Thomas O. Hicks, John R.
                       Muse, Charles W. Tate, Jack D. Furst, Lawrence D. Stuart,
                       Jr., Michael J. Levitt, Dan H. Blanks, and David B.
                       Deniger).

        10.26     -    Amended and Restated Stock Purchase Agreement dated
                       November 4, 1998, by and between Coho Energy, Inc. and
                       HM4 Coho, L.P. (incorporated by reference to Exhibit 99.1
                       to the Report on Form 8-K dated November 18, 1998).

       *10.27     -    Adoption Agreement for Coho Resources, Inc.'s Amended
                       and Restated 401(k) Savings Plan dated July 1, 1995.

        11.1      -    Statement re-computation of per share earnings.

        21.1      -    List of Subsidiaries of the Company.

        27        -    Financial Data Schedule
</TABLE>

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*  Represents management contract or compensatory plan or arrangement.



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