10-K 1 d95567e10-k.txt FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2001 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-K ---------- (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 ----------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______to ________. Commission file number 0-22576 COHO ENERGY, INC. (Exact name of registrant as specified in its charter) Texas 75-2488635 ------------------------------- --------------------- (State or other jurisdiction of (IRS Employer incorporation or organization) Identification Number) 14785 Preston Road, Suite 860 Dallas, Texas 75254 --------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (972) 774-8300 -------------- Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, par value $0.01 per share Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] As of March 28, 2002, 18,714,175 shares of the registrant's Common Stock were outstanding and the aggregate market value of all voting stock held by non-affiliates was $42,000 based upon the closing price on Nasdaq's OTC Bulletin Board on such date. The officers and directors of the registrant are considered affiliates for purposes of this calculation. TABLE OF CONTENTS

2 FORWARD-LOOKING STATEMENTS This Form 10-K includes statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, project, believe or anticipate will or may occur in the future, including: o crude oil and natural gas reserves; o future acquisitions; o future drilling and operations; o future capital expenditures; o future production costs; o future production of crude oil and natural gas; o future economic performance; and o future net cash flow of proved crude oil and natural gas reserves are forward-looking statements. These forward-looking statements are generally accompanied by words such as "intend," "anticipate," "believe," "estimate," "expect," "should" or similar expressions. These statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Important factors that could cause actual results to differ materially from our estimates or projections include, among others, the following: o the outcome of our bankruptcy proceedings and restrictions that may be placed on our operations during the pendency of the proceedings; o the substantial amount of our indebtedness; o the highly competitive nature of the oil and gas exploration and production business; o the timing and success of our exploration and development drilling programs, which would affect production levels and reserves; o changes to our estimates of oil and gas reserves; o the risk that our earnings may be adversely affected by fluctuating energy prices; o the business opportunities, or lack thereof, that may be presented to and pursued by us; o risks incident to the drilling and operation of oil and gas wells, including environmental liabilities; and o other factors, many of which are beyond our control. These types of statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. You should not rely on this information as an estimate or prediction of future performance. DEFINITIONS See Page 6 for a list of definitions of certain industry terms used throughout this document. 3 PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES GENERAL Coho Energy, Inc. is an independent energy company engaged, through its wholly owned subsidiaries, in the development and production of, and exploration for, crude oil and natural gas. Our crude oil activities are concentrated principally in Mississippi and Oklahoma. At December 31, 2001, our total proved reserves were 90.6 MMBOE with a net present value of proved reserves discounted at 10% of $352.4 million, approximately 70% of which were proved developed reserves, based on year end market prices of $19.84 per barrel for crude oil and $2.57 per MMbtu for natural gas. Approximately 96% of our total proved reserves were comprised of crude oil. At December 31, 2001, our operations were conducted in 19 major producing fields, 16 of which we operate. Our average working interest in the fields we operate was approximately 80%. We were incorporated in June 1993 under the laws of the State of Texas and conduct a majority of our operations through our subsidiaries Coho Resources, Inc. and Coho Oil & Gas, Inc. References in this Form 10-K to "Coho," "we," "our," or "us", except as otherwise indicated, refer to Coho Energy, Inc. and our subsidiaries. Our principal executive office is located at 14785 Preston Road, Suite 860, Dallas, Texas 75254, and our telephone number is (972) 774-8300. RECENT HISTORY AND BANKRUPTCY PROCEEDINGS We have carried a high level of indebtedness since emerging from bankruptcy in March 2000 with a ratio of consolidated indebtedness to total capitalization of 78% at March 31, 2000 and 82% at December 31, 2001. In April 2001, we entered into an agreement with JP Morgan, a division of Chase Securities, to act as our financial advisor in evaluating various potential strategic transactions to reduce our high level of indebtedness including: o various potential recapitalization transactions; o the sale of a portion of our company to provide working capital for our remaining properties; or o the sale of all of our company. In September and October 2001, we engaged in active negotiations with a third party for the sale of our Mississippi properties for $80 million but we were unable to close the transaction. During 2001, we continued with our operating business strategy that focused on relatively low-risk development activities. We expected this development activity to generate increases in production, cash flow from operations and proved developed reserves. Our development activity was successful in increasing production and cash flow from operations but not at the levels we had expected and not at levels sufficient to offset declines in crude oil and natural gas prices during the year combined with higher operating costs. Our development activity was also not successful in increasing proved developed reserves as discussed more fully under "Oil and Gas Operations." On November 1, 2001, the lenders under the senior revolving credit facility notified us that our borrowing base under this facility had been redetermined in the semi-annual review from $195 million to $175 million effective November 1, 2001. On November 2, 2001, we received a notice of borrowing base deficiency because borrowings under the credit facility exceeded the redetermined borrowing base by $20 million. In December 2001, we hired a new financial advisor, CIBC World Markets Corp., to assist us in developing a strategy to address our liquidity problems since JP Morgan, as one of our bank lenders, could no longer serve in this capacity. We did not have sufficient working capital to cure the borrowing base deficiency within the 90-day cure period and on February 1, 2002 a notice of default was issued by the lenders under the senior revolving credit facility. On February 6, 2002, we and our wholly owned subsidiaries, Coho Resources, Inc. and Coho Oil & Gas, Inc., filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Northern District of Texas. The bankruptcy petitions were filed to protect us while we develop a solution to our liquidity problems. We are currently operating as debtor-in-possession under the court's supervision 4 and pursuant to the court's orders. We filed schedules with the bankruptcy court on March 8, 2002. Those schedules contain our unaudited, and in some cases, estimated assets and liabilities as of February 6, 2002, as shown by our accounting records. Under our cash collateral order, we have agreed with the lenders under the senior credit facility to develop a marketing plan with our new financial advisor, CIBC, for the sale of our assets or a recapitalization of our debt and equity. We, together with CIBC, are currently working with our bank group and the unsecured creditors committee on mutually acceptable terms for this marketing plan to achieve maximum value for our assets in this process. We expect that once finalized and approved, the marketing plan will allow us to explore other alternatives available to us, in addition to a sale of our assets, including a recapitalization of our debt and equity assuming we are able to raise sufficient equity from existing or new investors to cure the $20 million borrowing base deficiency under our credit facility and to provide working capital to develop our properties. A recapitalization may include a partial sale of our assets. Any sale or recapitalization will be subject to bankruptcy court approval under a Chapter 11 plan of reorganization or liquidation or in accordance with Section 363 of the bankruptcy code, which generally provides for a partial sale of assets prior to confirmation of a plan of reorganization or liquidation. At this time, it is not possible to predict the outcome of the bankruptcy proceedings, in general, or the effect on our business or on the interests of the creditors or shareholders. We believe, however, that it may not be possible to satisfy in full all of the claims against us. In addition, the shareholders of our company may not realize any value on their investment. As a result of the bankruptcy filing, all of our liabilities incurred prior to February 6, 2002, including secured debt, are subject to compromise. Under the bankruptcy code, payment of these liabilities may not be made except pursuant to a plan of reorganization or liquidation or bankruptcy court approval. The financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts (including $333 million in net property, plant and equipment) or the amount and classification of liabilities that might result should we be unable to continue as a going concern. Our ability to continue as a going concern is dependent upon the confirmation of a plan of reorganization, adequate sources of capital and the ability to sustain positive results of operations and cash flows sufficient to continue to explore for and develop proved oil and gas reserves. These factors, among others, raise substantial doubt concerning our ability to continue as a going concern. OUR HISTORY Mississippi. We commenced operations in Mississippi in the early 1980s and have focused most of our development efforts in that area. The salt basin in central Mississippi offered significant long-term potential due to the basin's large number of mature fields with multiple oil and gas producing sands. The application of proven technology to these underexploited and underexplored fields yielded attractive, lower-risk exploitation and exploration opportunities. As a result of the attractive geology and our experience in exploiting fields in the area, we have accumulated an inventory of potential development drilling, secondary recovery and exploration projects in this basin. Oklahoma. One of our business strategies has been to acquire additional properties with geologically complex environments and features similar to our Mississippi properties and to fully exploit the acquired properties using our substantial knowledge base and geological expertise gained from our historical success in Mississippi. In December 1997, we acquired properties from Amoco Production Company that we believed presented the exploitation opportunity we were seeking. The properties we acquired from Amoco Production Company had approximately 55 MMBOE total proved reserves and represented interests in more than 40,000 gross acres, concentrated primarily in southern Oklahoma, including 12 principal producing fields. We paid $260.9 million in cash and stock warrants to acquire these properties. Louisiana. On December 2, 1998, we sold our natural gas assets located in Monroe, Louisiana, for a net sales price of $61.5 million. The assets sold represented approximately 14% of our year end 1997 proved reserves and included two gas gathering systems. March 2000 Reorganization. On August 23, 1999, we and our then wholly-owned subsidiaries, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production Company and Interstate Natural Gas Company, filed a voluntary petition for relief under Chapter 11 of the U. S. Bankruptcy Code. We then filed a plan of reorganization that was confirmed by the bankruptcy court on March 20, 2000. On March 31, 2000, the plan of reorganization was consummated and we emerged from bankruptcy. 5 The plan of reorganization included the following transactions to complete the restructuring of our indebtedness: o The borrowing of $183.0 million under our new revolving credit facility with a new bank group. o The borrowing of $72.0 million under senior subordinated notes referred to as the standby loan, maturing March 2007. We also issued 2,694,841 shares of new common stock, representing 14.4% of our new common stock, as debt issuance costs to the lenders under these notes. o The repayment of borrowings and interest due under the old bank credit facility. o Conversion of the old bonds into 15,362,107 shares of new common stock, representing 82% of our new common stock. As a result of the reorganization, our former principal bondholders and their affiliates owned approximately 88% of our new common stock after the reorganization and owned $65.5 million of the outstanding senior subordinated notes issued under our $72 million standby loan. Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Credit Facilities" for a description of the terms of the standby loan. Effective December 31, 2000, Coho Exploration, Inc., Coho Louisiana Production Company and Interstate Natural Gas were merged into Coho Resources, Inc. and ceased to exist as separate entities. DEFINITIONS Unless otherwise indicated, natural gas volumes are stated at the legal pressure base of the State or area in which the reserves are located at 60 degrees Fahrenheit. The following definitions apply to the technical terms used in this Form 10-K: "2-D seismic" means an interpretive data set that allows a view of a vertical cross-section beneath a prospective area. "3-D seismic" means an interpretive data set that allows a view of a vertical cross-section as well as a horizontal cross-section beneath a prospective area. "Bbls" means barrels of crude oil, condensate or natural gas liquids, and is equivalent to 42 U.S. gallons. "Bcf" means billions of cubic feet. "BOE" means barrel of oil equivalent, assuming a ratio of six Mcf to one Bbl. "BOPD" means Bbls per day. "Developed acreage" means acreage which consists of acres spaced or assignable to productive wells. "Dry hole" means a well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well. "Gravity" means the Standard American Petroleum Institute method for specifying the density of crude petroleum. "Gross" means the number of wells or acres in which we have an interest. "MBbls" means thousands of Bbls. "MBOE" means thousands of BOE. "Mcf" means thousands of cubic feet. "MMBbls" means millions of Bbls. "MMBOE" means millions of BOE. 6 "MMbtu" means millions of British Thermal Units. "MMcf" means millions of cubic feet. "Net" is determined by multiplying gross wells or acres by our working interest in such wells or acres. "Present value of proved reserves" means the present value discounted at 10% of estimated future net cash flows before income taxes of proved crude oil and natural gas reserves. "Productive well" means a well that is not a dry hole. "Proved developed reserves" means only those proved reserves expected to be recovered from existing completion intervals in existing wells and those proved reserves that exist behind the casing of existing wells when the cost of making those proved reserves available for production is relatively small relative to the cost of a new well. "Proved reserves" means natural gas, crude oil, condensate and natural gas liquids on a net revenue interest basis, found to be commercially recoverable. "Proved undeveloped reserves" means those reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. "Recompletion" means leaving one formation for another formation within a well bore. "Secondary recovery" means a method of oil and natural gas extraction in which energy sources extrinsic to the reservoir are used. "Undeveloped acreage" means leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether or not that acreage contains proved reserves. "Unitized" means the royalty and working interests are pooled within a given geological and/or geographical area. "Waterflood" means the injection of water into oil bearing formations to displace the oil. "Workover" means the performing of work within a well bore associated with the currently producing formation. OIL AND GAS OPERATIONS Since emerging from bankruptcy in March 2000, we have focused our capital expenditures on relatively low-risk development activities, such as development and delineation drilling, multi-zone recompletions, enhancement and/or expansion of existing secondary recovery projects that we expected to generate increases in production and cash flow from operations and to increase our proved developed producing reserves by developing our proved undeveloped reserves. Our capital expenditure program implemented over the last 18 months included development activities in Mississippi together with a few exploration opportunities in Oklahoma that we anticipated would provide increases in production in the near term to provide the necessary cash flow to support our longer term waterflood development activities in Oklahoma. Unfortunately, the production increases we achieved from these short-term development activities in Mississippi and exploration activities in Oklahoma did not meet our expectations and did not substantially increase our production, which was partially due to normal production declines, primarily in our Mississippi fields. During 2002, we will continue this development strategy, but on a smaller scale due to capital constraints, with a focus on opportunities with near term production increases. Due to our capital constraints, our emphasis will be on maintaining existing production and trying to offset normal production declines. 7 General. In the conduct of our operations, we apply the latest developments in technology, completion and production techniques, and we employ new innovations in equipment to enhance exploitation, secondary recovery and exploration activities on oil and gas properties. The detailed application of these areas of our expertise to older properties has played an important role in our continuing production and reserve development. In 2001, we conducted our operations mainly on the following fields: o Mississippi - Brookhaven, Martinville and Soso; and o Oklahoma - Tatums, East Fitts, East Velma Middle Block, Eola, and Jennings Deese. Our capital expenditures totaled $6.3 million in 1999, $25.3 million in 2000, and $33.2 million in 2001. We kept our 1999 capital expenditures very low due to budget constraints resulting from the substantial decline in crude oil prices in 1998 and early 1999, as well as expenditure constraints imposed by the bankruptcy court subsequent to August 23, 1999. In mid-year 2000, we resumed our development drilling program and drilled a total of 23 gross or 15.8 net development wells with a success rate of 87%. In 2001, we continued with this capital plan and drilled a total of 35 gross or 26 net wells with a success rate of 91%. We also participated in the drilling of seven gross, or .2 net wells that were completed as oil producers in two outside operated Oklahoma properties during 2001. We plan to continue development drilling and recompletion activity on a substantially reduced basis in 2002 due to expenditure constraints imposed by our cash collateral order under our current bankruptcy proceedings. Exploitation. Our properties are generally characterized as being mature and having multiple layers of oil and gas reservoirs, which are broken into numerous separate sources of supply due to the complex geology in many of the fields in which we operate. Our properties have a large number of wells that either we or other operators have drilled over the past 50 years. The data from these wells assists us in developing detailed geologic interpretations of our active regions, which continue to improve our understanding of the numerous hydrocarbon deposits on these properties. The changing economics of the value of these multiple reservoirs coupled with the ability to deploy capital and improved technology to identify and develop these sources of supply, presents us with new opportunities to produce reserves that were previously unattractive, unrecognized as productive or found to be isolated from the existing producing wells on a property. We have concentrated on the full development of mature fields that exhibit the potential for having been either underdeveloped or having further exploration opportunities through the utilization of new or existing technology. Secondary Recovery. The mature nature of our producing properties has provided us with opportunities to employ secondary recovery techniques to increase the recovery of reserves in place that have not been recovered by primary production means. In the majority of situations, the existing wells are utilized for this purpose, which greatly reduces the capital outlays otherwise necessary to connect to these sources of production. In addition, the water produced from these operations, as well as water from supplementary sources, is re-injected into the reservoir creating a so-called water-drive mechanism to extract the oil which was not produced under primary means. These projects have historically demonstrated strong production response and meaningful reserve additions. We have identified 20 potential secondary projects in Mississippi. Prior to 2000 we successfully developed six of these projects and during 2000, we initiated work on a seventh project in the Brookhaven field. Based on the results of this recent waterflood project in the Brookhaven field we have selected several other areas in the field which should present opportunities to further develop secondary reserves using existing well bores and facilities. The acquisition of the Oklahoma properties in 1997 presented us with nine existing secondary projects and we have identified 14 additional potential secondary projects on these properties. During 2000 and 2001, we initiated work on nine of these 14 waterflood projects. In late 2000, we initiated the installation of facilities and conversion or repair of available well bores to serve the Sims and Humphreys reservoirs in the East Velma Middle Block Unit with work continuing throughout 2001. In 2001, we initiated two new pilot waterflood projects in the Bumpass Unit to serve the Goodwin and Flattop reservoirs to evaluate their response to water injection and determine the economic feasibility of installing a complete waterflood project. In addition, pilot waterflood projects were initiated to further explore the potential for additional secondary reserve recovery in the Jennings Deese Unit, Graham Deese Unit, North Alma Deese Unit, Tatums Unit and East Fitts Unit which were under waterflood operations at the time they were acquired in late 1997. The purpose of these pilot waterflood projects is to determine the potential for improving the waterflood performance of the existing reservoirs, which are believed to have not been subjected to 8 effective water injection by the current on-going waterflood in these fields. Early indications, based upon evidence of response, are that the pilot waterfloods will demonstrate that additional reserves can be recovered at economically attractive levels by concentrating higher pressure, increasing density, or modifying of the existing waterflood projects. Exploration. The complex geology of many of our oil and gas properties provides us with the opportunity to drill for new sources of supply within the area of our existing properties and to utilize the existing well control to substantially reduce dry hole risk. In order to further define our targets and assist in the geologic interpretation of these complex features, we have completed two 3-D seismic surveys in Mississippi in the Martinville and Laurel fields resulting in 37 square miles and 24 square miles of data, respectively, and are in the process of evaluating approximately 95 square miles of 3-D seismic data and 2,750 miles of 2-D seismic data acquired along with the Oklahoma properties. 2-D seismic data is a tool that allows us to look at vertical cross-sections beneath the prospective area of our properties typically on a much wider grid pattern. A 3-D seismic survey is a computer enhanced seismic survey that allows us to look at subsurface structures in an area in a three dimensional view and provides much greater detail and resolution of the geologic picture than using 2-D seismic data alone. This seismic data as well as our geologic interpretations has provided us with excellent opportunities to utilize this data to explore for new sources of supply in areas where we are familiar with the overall geologic picture and hydrocarbon trapping mechanisms. PRINCIPAL AREAS OF ACTIVITY The following table sets forth, for our major producing areas, average net daily production of crude oil and natural gas on a BOE basis for each of the years in the three-year period ended December 31, 2001, and the number of productive wells producing at December 31, 2001.

(a) In response to depressed crude oil prices during early 1999, we significantly reduced minor and major repairs and drilling activity on our operated properties, ceased all repair work and drilling activity and halted production on wells we determined to be uneconomical. We restarted repairs and maintenance on the properties we operate and began doing limited recompletion and workover activity in the second half of 1999. After we emerged from bankruptcy in April 2000, we initiated a capital expenditure program that commenced in June 2000 to return all remaining shut-in wells to production and to begin drilling and recompletion projects to increase production. MID-CONTINENT AREA In December 1997, we acquired interests in approximately 40,000 gross acres concentrated primarily in southern Oklahoma, including 12 principal producing fields. Of the 12 principal producing fields, we are the operator of ten fields. At December 31, 2001, we had an average working interest of approximately 75% in the ten fields we operate. These properties are very similar to our Mississippi salt basin operations and we should be able to recover additional reserves not yet developed through detailed study and exploitation of these properties. In 2001, we drilled a total of 29 gross wells. We drilled two dry holes in the drilling program, which resulted in a successful completion rate of 93%. One dry hole was drilled in the Eola field at a total depth of 2,250 feet and the other dry hole was drilled in the Tatums field at a depth of 3,001 feet. Both dry holes were attempts to drill for shallow infield pay intervals, which were found to be unattractive for commercial production and were abandoned without attempting to complete the wells. The largest number of wells drilled in a particular field were the 16 wells drilled in the Tatums Field, including the one dry hole mentioned earlier, where we have a 49% working interest. One of the more significant wells was drilled in the Eola field to test a new fault block by re-entering an existing well and 9 directionally drilling to the objective in the McLish and Bromide sands. This well was completed in March 2001 and had an initial production rate of 275 BOE per day gross, or 238 BOE per day net. Two offset locations were subsequently drilled as a result of the subsurface control gained by the drilling of the initial well and as of December 2001, these were in the early stages of being tested and stimulation plans were being formulated to treat these wells in early 2002. After stimulating both wells, the combined initial production rate is 60 BOE per day net to our interest which is significantly below our expected levels for these wells. The remaining drilling in 2001 was in the East Fitts field with four wells drilled and the Jennings Deese primary field with five wells drilled. East Fitts Field, Oklahoma. The East Fitts field was discovered in 1933 and is located in Pontotoc County, Oklahoma near the city of Ada. Production in the field is primarily from the Cromwell, Hunton and Viola reservoirs ranging in depth from 2,400 feet to 5,000 feet. Our average working interest in the East Fitts field is approximately 82%. The East Fitts field is our largest property in Oklahoma and as of December 2001 had a total of 129 gross producing wells, 73 gross service wells and a total of 79 gross inactive wells. The field is primarily an oil producer and a waterflood has been active in the field for a number of years. In 2001, we continued the infill drilling program that had been initiated in 2000. This infill drilling program is designed to recover unswept oil reserves from areas of the reservoir by increasing the density of the drilling pattern from the historic ten-acre development to a five-acre drainage pattern. A total of four wells were drilled in 2001, as part of this infill project and resulted in three producers and one of the wells encountered a high pressure waterflow and was abandoned with the plan to re-enter at a later date with suitable drilling equipment and continue the completion. The three wells drilled and completed were the EFU 13-7, 26-3, and 26-4. The well, which was abandoned with plans to complete it later, was the EFU 13-8. The net daily initial combined production rate from the three wells drilled was 144 BOE, and the success of these wells further confirmed that there are areas of high oil saturation between the existing waterflood pattern and the new higher density well pattern. As a result of these findings, there are over 80 identified drilling locations, which could be suited to this higher density well pattern in the existing limits of the East Fitts field. In addition to the in-field drilling program, we concentrated on improving the water injection effectiveness within the East Fitts field by activating and repairing injection pumping equipment to increase our capacity. In 2001, we increased water injection volumes by approximately 14,000 barrels of water per day and brought the total daily water injection up to approximately 84,000 barrels. The additional injection is expected to provide us with better sweep efficiency in the existing waterflood and thus increase recovery and daily production rates. The field had an average net daily production of 1,252 BOE in 2001, which was an approximate 6% increase over the average net daily production of 1,182 BOE seen in 2000. Net proved reserves at December 31, 2001, totaled 22.7 MMBOE, which represented approximately 25% of our total net proved reserves, as compared to year-end net proved reserves at December 31, 2000 of 23.1 MMBOE. The reduction in net proved reserves from 2000 to 2001 was due primarily to reserves produced during 2001. East Velma Middle Block Field, Oklahoma. The East Velma Middle Block is located in Stephens County, Oklahoma and was discovered in 1949. The field has been a primary producer in the Sims and Humphreys formations. The field is characterized as a steeply dipping structure with a large trapping fault. Our average working interest in this field is 61%. In 2000, work was initiated to install a waterflood secondary production operation in the field to recover reserves that had not been produced under primary production methods. The East Velma Middle Block sits between two other outside operated properties on this same structure that had been waterflooded with excellent success. We began work in 2000 and were able to commence water injection operations on a limited scale. We have now completed the conversion of 17 wells to injection service and have completed six water supply wells. We are currently injecting a total of approximately 16,700 barrels of water per day. In 2001, we laid a water supply line from wells in an offset field, to provide increased water supply. This supply line is to commence operation in the first quarter of 2002 and is expected to increase our injection volumes by up to 25,000 barrels of water per day. We spent a total of roughly $2.7 million on the East Velma Middle Block in 2001 and completed the major portion of the project on the western half of the unit. We plan to spend $1.5 million during 2002 to complete the western half of the unit and to continue the waterflood installation in the eastern half of the unit. We estimate that an additional $2 million will be required in 2003 to complete the installation of the waterflood facilities in the eastern portion of the unit. 10 Proved net reserves totaled 10.6 MMBOE as of December 31, 2001, representing approximately 13% of our total proved reserves, as compared to proved net reserves of 11.6 MMBOE at December 31, 2000. The decrease in net proved reserves is primarily due to: o downward revisions of natural gas reserves because some gas wells were converted to water injection wells for the waterflood project; o decreases in the value of reserves related to lower crude oil and natural gas prices between years; and o reserves produced during 2001. Daily average net production from the East Middle Block field in 2001 averaged 462 BOE down from the 516 BOE experienced in 2000. Although the overall net production average for 2001 was below the 2000 level, we have seen production improvements in the later half of 2001 indicating that we are seeing production response from water injection. We anticipate further production response in 2002 as we significantly increase daily water injection volumes. Tatums Field, Oklahoma. The Tatums field is located in Carter County, Oklahoma and was discovered in 1927. The field is primarily a Deese sand structure between the average depths of 2,500 and 3,000 feet. Our average working interest in the Tatums field is 49%. As of December 2001, there were 112 gross producing wells and 55 gross water injection or service wells active in the field. In addition, there are 66 gross available wellbores, which are currently inactive in the field. During 2000, we reprocessed our 3-D seismic in the Tatums field, and were able to discern that the field was made up of a number of flow channels primarily in the Deese reservoir, which had not been previously recognized. We began an in-field development drilling program during 2000 and drilled a total of eleven gross wells confirming that high oil saturations remained in the areas delineated by the reprocessed seismic. In 2001, we continued on this drilling project and drilled a total of 16 gross wells, with one dry hole, which we did not attempt to complete. In order to supply this new drilling area with water injection to re-pressure the reservoir and recover the remaining oil, we expanded the existing water injection facilities and lines to extend into this area. We are currently injecting water into the extended area of the field. Based on the success of these injection efforts, we plan to continue to develop this area through additional drilling in 2002. Net daily production from the Tatums field in 2001 averaged 669 BOE, representing an increase of 12%, as compared to average net daily production of 597 BOE in 2000. The Tatums field also had a 12% increase in average net daily production from 1999 to 2000. Total net proved reserves as of December 31, 2001 were 3.9 MMBOE, as compared to total net proved reserves as of December 31, 2000 of 3.5 MMBOE. Net proved reserves have increased in 2000 and 2001 by 7% and 10%, respectively. Other Oklahoma. We operate seven other fields in Oklahoma: o Bumpass (Carter County; working interest 63%); o Cox Penn (Carter County; working interest 99%); o Eola (Garvin County; working interest 87%); o Graham Deese (Carter County; working interest 63%); o Jennings Deese (Carter County; working interest 85%); o North Alma Deese (Stephens County; working interest 96%); and o Sholem Alechem Fault Block "A" (Stephens County; working interest 87%). 11 As discussed under "Secondary Recovery", we launched pilot waterflood projects in the North Alma Deese, Graham Deese and Bumpass fields during 2000 and continued work on these projects during 2001. Continued monitoring of these waterflood projects for response while we continue to inject water and optimize lifting equipment to handle increased production will be our focus in 2002 due to capital constraints. Total average net daily production in 2001 from these fields was 2,403 BOE, a 3% increase, as compared to average net daily production of 2,330 BOE in 2000. At December 31, 2001, net proved reserves in these fields were approximately 26.4 MMBOE as compared to net proved reserves of 28.0 MMBOE at December 31, 2000. The 6% decline in reserves between years is due to reserves produced during 2001 and lower crude oil and natural gas prices used in the reserve evaluation at December 31, 2001. We also have working interests in producing properties that are operated by other companies. These properties are located in various counties in Oklahoma with the primary counties being Stephens, Garvin and Carter. At December 31, 2001, net proved reserves in these fields were estimated at 2.1 MMBOE as compared to net reserves of 2.7 MMBOE at December 31, 2000. The 25% decline in reserves between the comparable periods is due to lower crude oil and natural gas prices used in the reserve evaluation at December 31, 2001 as compared to yearend 2000 and reserves produced during 2001. Net average daily production from these properties was 832 BOE in 2001 as compared to average net daily production of 973 BOE in 2000. GULF COAST AREA Brookhaven Field, Mississippi. The Brookhaven field is located in Lincoln County, Mississippi near the town of Brookhaven. The field was discovered in 1943 and covers a surface area of approximately 13,000 acres. We acquired the Brookhaven field in 1995 and currently own an average working interest of 98% in the field. Productive intervals in the field range from the Tuscaloosa formation at approximately 10,500 feet to the Hosston formation at 16,700 feet. The Tuscaloosa formation was the primary reservoir that was developed in the field, until we added the Washita Fredericksburg, Paluxy and Rodessa formations through deeper exploratory drilling. The Brookhaven field produces some of our highest quality crude oil in the State of Mississippi which results in higher prices. In 2001, we drilled the BFU 32N-15 Well No. 1 at a cost of approximately $928,000 to a total depth of 13,700 feet in an attempt to extend the production limits of the Washita Fredericksburg formation based upon 2-D seismic available in the area and the successful completion of the BFU 5-2 Well No. 2 in 2000 with an initial daily production rate of 288 BOE per day gross or 205 BOE per day net. The well was not completed as the expected geologic structure was found structurally lower and non-commercial. The well was plugged without any attempt to make a completion or test. Subsequent analysis of the seismic interpretation showed that a velocity anomaly existed in this area of the field, which caused the seismic interpretation to indicate a structural high that did not exist. In late 2000, we initiated a secondary project as a pilot waterflood operation to evaluate the potential of initiating water injection efforts in selected areas of the Tuscaloosa reservoir which were believed to have not been effectively drained by past production methods. In 2001, we spent a total of $1.5 million to install water injection pumps, injection lines and facilities to serve this project. Included in the expenditure was the conversion of two wells to serve as water injection wells, and an additional three available wellbores have been completed as producing wells for the project. We are currently injecting 600 barrels of water a day into this project and are producing approximately 100 BOPD as a response to this waterflood installation. The performance of this project has enabled us to add approximately 180 MBbls of proved producing reserves. Based on these results, we plan to initiate a new waterflood in 2002 by converting two additional available wellbores to serve as water injection wells. We have identified a minimum of two other distinct areas where we expect waterflooding operations to have the same favorable results as in the Brookhaven field, and we intend to develop engineering designs to recommend their development as capital becomes available. In 2001, the total net daily average production from the Brookhaven field was 716 BOE, an increase of approximately 39% over the 514 BOE net daily average production in 2000. Net proved reserves at December 31, 2001 were 4.1 MMBOE reflecting a decline of 21% from net proved reserves of 5.2 MMBOE at December 31, 2000. The reduction in reserves is primarily due to downward revisions in reserves due to the unsuccessful drilling of the BFU 32N-15 Well No. 1, discussed previously, together with decreases in reserves related to reserves produced during 2001 and lower crude oil and natural gas prices at year end 2001 as compared to year end 2000. 12 Laurel Field, Mississippi. The Laurel field is located in Jones County, Mississippi and lies predominantly within Laurel city limits. We acquired our initial interest in this field in 1983 and currently own an average working interest of 95% in the field. The field is a multi-pay geologic structure known as a "salt dome" with known hydrocarbon production formations ranging in depth from 7,500 feet to 13,500 feet. The Laurel field is our largest oil producing property and represented approximately 41% of our total Mississippi production on a BOE basis in 2001. In 2001, we concentrated our work on maintaining production from existing wells and improving the effectiveness of the secondary recovery projects that were underway in the field. There were no wells drilled in the Laurel field during 2001, although several locations were identified and initial plans did include the drilling of two locations. However, the decline in crude oil and natural gas prices during the year caused us to eliminate the drilling program in 2001. In 2001, we completed 21 well repairs and three recompletions. The average net daily production in 2001 from the Laurel field was 2,058 BOE representing a decrease in average net daily production of 7% from the same period in 2000. The primary reason for the decrease in production was due to normal production declines. As of December 31, 2001, net proved reserves were estimated at 8.5 MMBOE representing a decrease of approximately 14% from the December 31, 2000 year end reserves. The decrease in reserves is a result of the lower crude oil and natural gas prices at year end 2001 as compared to year end 2000 and production of reserves during 2001. Martinville Field, Mississippi. The Martinville Field is located in Simpson County, Mississippi. We acquired our initial interest in the Martinville field in 1989 and currently own an average working interest of 99% in the field. The productive limits of the field are estimated to cover more than 7,400 acres and at year end 2001, contained a total of 47 gross wells with 18 wells being operated as producing wells. The field is a complex deep-seated anticline geologic structure marked by extensive faulting and multiple productive horizons. The field consists of numerous hydrocarbon producing formations ranging in depth from approximately 8,500 to 14,500 feet. In 2001, we drilled two wells to develop reserves and both were successfully completed as producing oil wells. The combined initial net daily production rate from the two wells was 202 BOE. The remainder of our activity in the Martinville field during 2001 was concentrated on performing well repairs and recompletions on existing wells. In 2001, we completed seven well repairs and performed eight recompletion projects. Net proved reserves at year end 2001 totaled 3.1 MMBOE, a decrease of 23% from year end 2000. The decrease in reserves is primarily due to a reduction in reserves due to lower crude oil and natural gas prices at December 31, 2001 and reserves produced during 2001. Production in 2001 averaged a daily net of 667 BOE and represented an increase of approximately 3% from the average daily net production for 2000. Soso Field, Mississippi. The Soso Field is located in Smith and Jones Counties, Mississippi and covers approximately 6,500 acres. We acquired our initial interest in this field in 1990 and currently own an average working interest of 94% in the field. Since 1997, we have concentrated the majority of our efforts to initiate and manage a water injection program for the Cotton Valley, Sligo and Rodessa formations, which were previously producing in the field under primary recovery methods. In 2001, we drilled two development wells to provide additional recovery in the Cotton Valley reservoir and to take advantage of the water sweep being provided by the water injection program. These two wells were completed as oil producers with a combined initial net daily production rate of 137 BOE. The results from these two Cotton Valley wells were disappointing since our expected combined initial production rate was 600 BOE per day. Additional activity in 2001 centered on well repairs and recompletion work to maintain production. A total of nine recompletions and 10 well repairs were completed in 2001. Net proved reserves at year end 2001 totaled 3.7 MMBOE and represented a decrease of 27% in net proved reserves from the prior year. The decrease in reserves is due primarily to downward revisions in reserves related to the Cotton Valley wells drilled in 2001 together with decreases in reserves related to production of reserves during 13 2001 and lower crude oil and natural gas prices at December 31, 2001. The poor drilling results on the two Cotton Valley wells resulted in a reduction in proved reserves of 464 MBOE. Additionally, we had attributed reserves of 234 MBOE in the Hosston formation that were proved non productive by drilling these wells. Summerland Field, Mississippi. The Summerland field is located in Jones and Covington Counties, Mississippi and covers approximately 1,300 acres. We acquired operating control of the Summerland field in 1989 and currently own an average working interest of 90%. The productive structure of the field is a broad, elongated, fault-bounded anticline with productive intervals from the Tuscaloosa formation at approximately 6,000 feet to the Mooringsport formation at 12,500 feet. At December 31, 2001, we operated 19 gross producing wells. In 2001, we directed our activity toward well repairs and recompletions in an effort to maintain production. We conducted a total of seven well repairs and seven recompletions. Average daily net production for 2002 for the Summerland field was 774 BOE or an increase of 8% from the average daily net production for 2001. At December 31, 2001, the Summerland field had proved reserves of 2.6 MMBOE, a decrease of approximately 34% from year end 2000. This decrease was primarily due to lower crude oil and natural gas prices at December 31, 2001 as compared to year 2000, poor production results from the recompletions performed in 2001 and reserves produced during 2001. OTHER DOMESTIC PROPERTIES We also have working interests in other producing properties in Mississippi and Texas. We operate the Bentonia (99% working interest) and Cranfield (100% working interest) fields in Mississippi and four gas wells in Navarro County, Texas (100% working interest) and we own non-operated working interests in the Glazier field (39% working interest) in Mississippi, the Clarksville field (43% working interest) in Texas and a field in Federal waters offshore North Padre Island, Texas (39% working interest). At year end 2001, we removed all proved reserves (453 MBOE) for the North Padre Island Block A-59, which is operated by El Paso Production due to the lack of success in attempts to workover the well in 2001. As of December 31, 2001, these fields had combined net proved reserves of 2.8 MMBOE as compared to 3.6 MMBOE at December 31, 2000. Aggregate average daily net production from these properties for 2001 was approximately 420 BOE as compared to 427 BOE for 2000. TUNISIAN OPERATIONS We decided to discontinue our participation in the exploration of two Tunisia, North Africa permits due to capital commitments during 2001 exceeding $7 million net to our interest. The two subsidiaries, Coho Anaguid, Inc. and Coho International Limited, that own these permits filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001. During May 2001, Coho International entered into a settlement agreement with the other joint owners in the permit area. Under this agreement, Coho International assigned its interest in the Fejaj permit to the other joint owners in exchange for the assumption by the other joint owners of Coho International's existing obligations and existing payables under the permit. During July 2001, Coho Anaguid, Inc. entered into a definitive agreement to sell all of its interest in the Anaguid permit to Pioneer Natural Resources Company and the other joint owners in the permit area for cash proceeds of approximately $200,000 and the assumption of Coho Anaguid's obligations under the permit totaling in excess of $7 million. These sales agreements have been approved by the United States Bankruptcy Court and the Tunisian government. We converted the bankruptcy proceedings for Coho Anaguid and Coho International from Chapter 11 reorganization proceedings to Chapter 7 liquidation proceedings during the first quarter of 2002 to wind down these proceedings. PRODUCTION The following table contains information regarding our production volumes, average prices received and average production costs associated with our sales of crude oil and natural gas for each of the years in the three-year period ended December 31, 2001: 14

(a) Includes the effects of crude oil price hedging contracts. Price per Bbl before the effect of hedging was $15.40 for the year ended December 31, 1999, $26.10 for the year ended December 31, 2000 and $20.66 for the year ended December 31, 2001. (b) Includes the effects of natural gas price hedging contracts. Price per Mcf before the effect of hedging was $2.24 for the year ended December 31, 1999, $3.99 for the year ended December 31, 2000 and $4.38 for the year ended December 31, 2001. (c) Includes lease operating expenses and production taxes. Average production costs per BOE increased from 1999 to 2000 primarily due to increases in production taxes, fluid production, utility costs, costs for well services and materials. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a more detailed discussion. DRILLING ACTIVITIES During the periods indicated, we drilled or participated in the drilling of the following wells:

(a) 1999 well was drilled in Tunisia, North Africa. (b) Included in drilling activities are wells deepened to a lower reservoir through existing well bores. In 1999, all wells under "Development" were deepenings within existing well bores. At December 31, 2001, we were not drilling any wells. RESERVES The following table summarizes our net proved crude oil and natural gas reserves as of December 31, 2001, which have been reviewed by Ryder Scott Company with regard to our Mississippi properties and Sproule Associates, Inc. with regard to our Oklahoma properties. The other properties in the table are related to our crude oil 15 and natural gas reserves located in Texas which have been audited, depending on location, by the independent engineers named in the preceding sentence.

At December 31, 2001, we had net proved developed reserves of 63,757 MBOE and net proved undeveloped reserves of 26,827 MBOE. The present value of proved reserves of $352.5 million represented $255.7 million for the proved developed reserves and $96.8 million for the proved undeveloped reserves. The present value of proved reserves is based on year end market prices of $19.84 per barrel for crude oil and $2.57 per MMbtu for natural gas. Market prices for crude oil and natural gas have fluctuated significantly over the last three years. At December 31, 2000, we reported total proved reserves of 100,778 MBOE, and the present value of proved reserves was $756.6 million with year end crude oil and natural gas prices of $26.80 per barrel and $9.78 per MMbtu, respectively. Reserves volumes and values declined from 2000 to 2001 primarily due to lower crude oil and natural gas prices used to prepare the 2001 year-end reserves as compared to the 2000 year-end reserves. Reserves produced during 2001 and downward revisions in reserve estimates also contributed to the decline in reserves. Following are the major changes in reserves due to price declines and downward revisions. o We estimate that the change in reserves from the difference in crude oil and natural gas prices between December 31, 2000 and December 31, 2001 represents a decrease of approximately 5.7 MMBOE to our net proved reserves and a related decrease of approximately $375.9 million in net present value of proved reserves. o The net 2,763 MMcf (453 MBOE) of natural gas reserves associated with North Padre Island field located in Federal waters, offshore Texas were removed from proved reserves during 2001 due to the lack of success in attempts to workover the well in 2001. o The drilling of the BFU 32N-15 Well No. 1 in the Brookhaven field to develop proved undeveloped reserves was unsuccessful due to the producing reservoir being encountered structurally low to prognosis. 16 The re-interpretation of the productive area of this producing reservoir has led us to remove four proved undeveloped locations from our net proved reserves totaling approximately 896 MBOE. o The poor drilling results on the two Cotton Valley wells in the Soso Field and the lack of success in encountering commercial production in the targeted Hosston interval in one of these Cotton Valley wells resulted in downward revisions in reserves of 698 MBOE. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves, including many factors beyond our control. The estimates of the reserve engineers are based on several assumptions, including the following: o future production; o revenues; o taxes; o production costs; o success of development drilling; o development expenditures; and o quantities of recoverable crude oil and natural gas reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth herein. In addition, our reserves might be subject to revision based upon: o actual production performance; o results of future development; o prevailing crude oil and natural gas prices; and o other factors. In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted. Except to the extent we acquire additional properties or additional interests in existing properties containing proved reserves or conduct successful exploration and development activities associated with our proved and unproved reserves, or both, our proved reserves will decline as reserves are produced. Future crude oil and natural gas production is therefore highly capital intensive and dependent upon the level of success in acquiring or finding additional reserves. For further information on reserves, costs relating to crude oil and natural gas activities and results in operations from producing activities, see "Supplementary Information Related to Oil and Gas Activities" appearing in Note 16 to our consolidated financial statements included in this Form 10-K. 17 ACREAGE The following table summarizes the developed and undeveloped acreage we owned or leased at December 31, 2001:

TITLE TO PROPERTIES As is customary in the oil and gas industry, in many circumstances, we make only a limited review of title to undeveloped crude oil and natural gas leases at the time we acquire them. However, before we acquire developed crude oil and natural gas properties, and before drilling commences on any leases, we cause a thorough title search to be conducted, and any material defects in title are remedied to the extent possible. To the extent title opinions or other investigations reflect title defects, we, rather than the seller of the undeveloped property, are typically obligated to cure any title defects at our expense. We could lose our entire investment in any property we drill, if we have a title defect of a nature that we could not remedy or cure. We believe that we have good title to our crude oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. The crude oil and natural gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties. COMPETITION The crude oil and natural gas industry is highly competitive. We encounter strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and production of, crude oil and natural gas. Competition is particularly intense with respect to the acquisition of desirable undeveloped crude oil and natural gas properties. The principal competitive factors in the acquisition of desirable undeveloped crude oil and natural gas properties include the staff and data necessary to identify, investigate and purchase these properties, and the financial resources necessary to acquire and develop these properties. Many of our competitors have financial resources, staff and facilities substantially greater than ours. In addition, the producing, processing and marketing of crude oil and natural gas is affected by a number of factors which are beyond our control, the effect of which cannot be accurately predicted. The principal resources necessary for the exploration and production of crude oil and natural gas are: o leasehold prospects under which crude oil and natural gas reserves may be discovered; o drilling rigs and related equipment to explore for these reserves; and o knowledgeable personnel to conduct all phases of crude oil and natural gas operations. We compete for these resources with both major crude oil and natural gas companies and independent operators. Although we believe our current operating and financial resources under our cash collateral order will be adequate to preclude any significant disruption of our operations in the immediate future, the continued availability of these materials and resources to us cannot be assured. CUSTOMERS AND MARKETS Substantially all of our Mississippi crude oil is sold under contracts which are based on posted crude oil prices and substantially all of our Oklahoma crude oil is sold under contracts which are based on the New York Mercantile Exchange price. In some circumstances, natural gas liquids are removed from our natural gas production and are sold by us at posted prices. During 2001, EOTT Energy Operating Limited Partnership, TEPPCO Crude Oil, L.P. and Sunoco, Inc. accounted for 41%, 30% and 13%, respectively, of our revenues. While we believe our relationships with EOTT, TEPPCO and Sunoco have been and will continue to be good, any loss of revenue from these customers due to nonpayment by the customer would have an adverse effect on our net income and earnings 18 per share on our income statement and, ultimately, may affect our share price. In addition, any significant late payment may adversely affect our short term liquidity position. The general partner of EOTT Energy Operating Limited Partnership is a wholly-owned subsidiary of Enron Corp. Each month we are requesting a letter of credit from EOTT for the purchase of our future month production to minimize credit risk that may exist due to their affiliation with Enron Corp. If we do not receive these letters of credit, any adverse developments relating to Enron Corp. that may have an adverse effect on EOTT may in turn impact EOTT's ability to fulfill its obligations to us. Effective November 1, 2000, we entered into a 14-month crude oil purchase agreement with EOTT. Under this crude oil purchase agreement, we committed the majority of our crude oil production in Mississippi to EOTT through December 31, 2001 on a pricing basis of posting plus a premium with adjustment made for gravity. This contract was extended to continue on a month-to-month basis during 2002 by mutual agreement of both parties. During 1999, we entered into a separate contract with EOTT to sell approximately 50% of our heavy Mississippi crude oil through December 31, 1999. This contract continues annually until terminated by either party and contains similar pricing arrangements based on postings plus a premium with an adjustment for gravity and sets a minimum wellhead price of $8.50 per barrel for this heavy crude oil. The majority of crude oil production in Oklahoma is sold to TEPPCO Crude Oil, L.P. and Sunoco, Inc. on a NYMEX pricing basis minus a discount with an additional discount for fluctuations in the price for our sour oil. Our contracts with Teppco and Sunoco expire on September 30, 2002. Pursuant to a purchase and sale agreement entered into in November 1997, Amoco has retained a right of first refusal to match, in all respects, a competitive bid for the purchase on an annual basis of our crude oil through 2007. During 2001, Amoco did not exercise their right to bid on our crude oil. The sales prices we receive for crude oil and natural gas may vary significantly during the year due to the volatility of the crude oil and natural gas markets, particularly during the cold winter and hot summer months. As a result, we periodically enter into forward sale agreements or other arrangements for a portion of our crude oil and natural gas production to hedge our exposure to price fluctuations. Gains and losses on these forward sale agreements are reflected in operating income at the time of sale of the related hedged production. While intended to reduce the effects of the volatility of the prices received for crude oil and natural gas, these hedging transactions may limit our potential gains if crude oil and natural gas prices were to rise substantially over the price established by the hedge. Effective January 1, 2002, we dedesignated the hedging relationship for the remainder of our hedges. Accordingly, all future unrealized gains and losses on our derivatives will be recognized through earnings. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Hedging Activities and Other Derivatives" and Note 1 to our consolidated financial statements for more information related to hedging. OFFICE AND FIELD FACILITIES We currently lease 26,751 square feet for our executive and administrative offices in Dallas, Texas, under a lease that continues through December 2005. We lease field offices in Laurel, Mississippi, covering approximately 5,000 square feet under a month-to-month lease. We are currently evaluating the Laurel lease as well as other alternatives. We also lease office space in Ratliff City, Oklahoma, covering approximately 10,000 square feet through January 2003. GOVERNMENTAL REGULATION Crude oil and natural gas exploration, development and production are subject to various types of regulation by local, state and federal agencies. These laws and regulations govern, among other things: o issuing permits and bonds in connection with drilling activities; o imposing a production severance tax; o regulating operations on secondary recovery projects; o regulating the location of wells; 19 o regulating the method of drilling and casing wells; o regulating the surface use and restoration of properties upon which wells are drilled; and o regulating the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations in which our properties are located, including those of Mississippi, Oklahoma and Texas. These laws and regulations include the regulation of: o the size of drilling and spacing units or proration units; o the density of wells that may be drilled; o unitization or pooling of crude oil and natural gas properties; o maximum rates of production from crude oil and natural gas wells; o restrictions on the venting or flaring of natural gas; and o requirements regarding the ratability of production. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of land and leases. The effect of these regulations is to limit the amount of crude oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the crude oil and natural gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are constantly amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Each state generally imposes a production or severance tax with respect to production and sale of crude oil, natural gas and natural gas liquids within their respective jurisdictions. For the most part, state production taxes are applied as a percentage of production or sales. Currently, we are subject to production tax rates of up to 6.2% in Mississippi and 7.2% in Oklahoma. Some of our operations are conducted on federal and Indian oil and gas leases that are subject to a variety of regulations and rules published by the United States Minerals Management Service and other federal agencies. For offshore leasing operations, the Minerals Service issues detailed regulations and orders which govern, among other things: o the approval for exploration, development and production plans; o the issuance of permits for drilling operations and drilling bonds; o the engineering and construction specifications for offshore production facilities; and o the plugging and abandonment of such wells. With respect to gas royalty valuation, the Minerals Service has published final rules that amend regulations governing valuation for royalty purposes of gas produced from federal and Indian leases. The Minerals Service has also published proposed rules to amend the current federal crude oil royalty valuation regulations and the current Indian crude oil royalty valuation regulations. With regards to the proposed rules, we cannot predict what action the Minerals Service might take on these matters, nor can we predict at this stage of the rulemaking proceedings how we might be affected by amendments to these regulations. With regards to the other regulations and amendments thereto, management believes that these regulations and amendments to the regulations have not had a material adverse effect on our results of operations. 20 The Federal Energy Regulatory Commission, in response to the Energy Policy Act of 1992, has implemented regulations establishing an indexing system for transportation rates for crude oil pipelines. The regulations would generally index transportation rates to inflation. These regulations may affect the price that we receive from the sale of crude oil due to a possible increase in the cost of transporting oil to market. We are not able to predict with certainty what effect, if any, these regulations will have on us, but other factors being equal, the regulations may tend to increase transportation costs or reduce wellhead prices for these commodities. The ultimate impact on us of these complex and overlapping rules and regulations, many of which are repeatedly subjected to judicial challenge and interpretation, cannot be predicted. ENVIRONMENTAL REGULATIONS Our oil and gas operations and properties are subject to numerous federal, state and local laws and regulations relating to environmental protection. These laws and regulations may: o require us to obtain permits before drilling; o restrict the types, quantities and concentration of various substances that can be released into the environment through drilling and production activities; o limit or prohibit drilling activities on some lands lying within wilderness, wildlife refuges or preserves, wetlands and other protected areas; o restrict the discharge of produced waters and other oil and gas wastes into navigable waters; o regulate the treatment, storage and disposal of hazardous and nonhazardous wastes; and o regulate the remediation of contaminated sites. In addition, these laws and regulations may impose substantial liabilities for our failure to comply with them or for any contamination resulting from our operations. We maintain insurance against losses or liabilities arising from our operations in accordance with customary industry practices and in amounts we believe reasonable. However, insurance is often not available against all operational risks or is not economically feasible for us to obtain. If a significant event occurs that imposes liability on us that is either not insured or not fully insured, a material adverse effect on our financial condition and results of operations could result. We take the issue of environmental responsibility very seriously and work diligently to comply with applicable federal, state and local environmental rules and regulations including but not limited to, the Oil Pollution Act of 1990, the Federal Water Pollution Control Act of 1972, the Comprehensive Environmental Response, Compensation, and Liability Act, as amended by the Superfund Amendments and Reauthorization Act, and the Resource Conservation and Recovery Act. We hold all the necessary permits for our operations and to the best of our knowledge are not the subject of any environmental investigation. Management believes compliance with environmental laws and regulations has not had a material adverse effect on our operations or financial condition in the past. To date, compliance with such laws and regulations has not materially affected our operations or financial condition. However, because environmental laws and regulations are becoming increasingly more stringent, there can be no assurances that such laws and regulations or any environmental law or regulation enacted in the future will not significantly affect our operations or financial condition. A significant portion of our operations in Mississippi is conducted within city limits. Each year we are required to meet tests of financial responsibility to obtain permits to conduct new drilling operations. We also continue to be involved in a voluntary program to remove inactive aboveground storage tanks from our well sites and to replace them, as necessary, with newer aboveground storage tanks. Some states have enacted statutes governing the handling, treatment, storage and disposal of waste containing naturally occurring radioactive material "NORM". NORM is present in varying concentrations in both surface and subsurface and hydrocarbon reservoirs around the world and may be concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Mississippi legislation prohibits the transfer of property for residential or other unrestricted use if the property evidences 21 concentrations of NORM above prescribed levels because of crude oil and natural gas production activities. We will be continuing our voluntary NORM remediation projects at several fields in Mississippi. EMPLOYEES At March 1, 2002, we had 72 employees associated with our operations, including 20 field personnel in Mississippi and 22 field personnel in Oklahoma. None of our employees is represented by a union. We consider our employee relations to be satisfactory. RISK FACTORS RELATED TO OUR BUSINESS WE HAVE FILED FOR BANKRUPTCY AND IT MAY NOT BE POSSIBLE FOR US TO CONTINUE AS A GOING CONCERN AND YOU MAY NOT RECEIVE ANY CASH IF WE LIQUIDATE ALL OF OUR ASSETS. On February 6, 2002, we and our wholly subsidiaries, Coho Resources, Inc. and Coho Oil & Gas, Inc., filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Northern District of Texas. The bankruptcy petitions were filed to protect us while we develop a solution to our liquidity problems. We are currently operating as debtor-in-possession under the court's supervision and pursuant to its orders. We have agreed with the lenders under the senior credit facility to develop a marketing plan with our new financial advisor, CIBC, for the sale of our assets or a recapitalization of our debt and equity. Any sale or recapitalization will be subject to bankruptcy court approval under a Chapter 11 plan of reorganization or liquidation or in accordance with Section 363 of the bankruptcy code, which generally provides for a partial sale of assets prior to confirmation of a plan of reorganization or liquidation. At this time, it is not possible to predict the outcome of the bankruptcy proceedings, in general, or the effect of the bankruptcy on our business or on the interests of the creditors or shareholders. We believe, however, that it may not be possible to satisfy in full all of the claims against us. In addition, the shareholders of our company may not realize any value on their investment. THE BANKRUPTCY MAY HAVE CREATED A NEGATIVE IMAGE OF US. We cannot predict whether our bankruptcy filing will have a negative effect, if any, on our operations. Although we believe that the bankruptcy filing has had and will continue to have a minimal effect on our relationships with our customers, employees and suppliers, we cannot assure you that there will not be a detrimental impact on future sales and patronage because of the negative image of us that may have been created by the bankruptcy. LIQUIDITY AND COURT IMPOSED CONSTRAINTS MAY HINDER OUR CONTINUED OIL AND GAS OPERATIONS. Since filing for bankruptcy protection on February 6, 2002, we have been operating under the constraints of a cash collateral order and we are subject to expenditure constraints imposed by the bankruptcy court. Our only sources of liquidity during the pendency of the bankruptcy proceeding will be cash on hand and cash generated by operations. PAST SUBSTANTIAL NET LOSSES MAY AFFECT FUTURE OPERATIONS. We experienced substantial net losses for the years ended December 31, 1999 and 2000 of $30.7 million and $32.7 million, respectively. For the year ended December 31, 2001, we experienced a loss before accumulated effect of an accounting change of $4.4 million. If we continue as a going concern, we may not become profitable in the future. WE MAY NOT BE ABLE TO REPLACE DEPLETED RESERVES AT A LEVEL NECESSARY TO CONTINUE OUR CURRENT PRODUCTION LEVEL. The rate of production from crude oil and natural gas properties declines as reserves are depleted. Except to the extent we acquire additional properties containing proved reserves, or conduct successful exploration and development activities that identify additional formations with primary or secondary reserve opportunities on our own properties, our proved reserves will decline as reserves are produced. Future crude oil and natural gas production is therefore highly dependent on our level of success in finding and acquiring additional reserves. Our 22 ability to acquire producing properties assumes that major integrated oil companies and independent oil companies will continue to divest some of their crude oil and natural gas properties. These divestitures may not continue and we may not be able to acquire producing properties at acceptable prices. Our ability to develop or acquire additional reserves is limited due to the capital constraints imposed by the bankruptcy court. OUR HIGH LEVEL OF DEPENDENCE ON THREE MAIN CUSTOMERS MAY DIRECTLY AFFECT OUR INCOME STATEMENT. During 2001, three purchasers of our crude oil and natural gas, EOTT Energy Operating Limited Partnership, TEPPCO Crude Oil, L.P. and Sunoco, Inc. accounted for 41%, 30% and 13%, respectively, of our revenues. While we believe that our relationships with EOTT, TEPPCO and Sunoco have been and will continue to be good, any loss of revenue from these customers due to nonpayment by the customer would have an adverse effect on our net income and earnings per share on our income statement and, ultimately, may effect our share price. In addition, any significant late payment may adversely effect our short-term liquidity position. The general partner of EOTT Energy Operating Limited Partnership is a wholly-owned subsidiary of Enron Corp. Each month we are requesting a letter of credit from EOTT for the purchase of our future month production to minimize our potential credit risk that may exist due to their affiliation with Enron Corp. If we do not receive this letter of credit, any adverse developments relating to Enron Corp. that may have an adverse effect on EOTT may in turn impact EOTT's ability to fulfill its obligation to us. IF WE ARE UNABLE TO COMPETE EFFECTIVELY AGAINST MAJOR OIL COMPANIES AND OTHER INDEPENDENT OPERATORS, WE MAY BE UNABLE TO OBTAIN NECESSARY MATERIALS AND RESOURCES AND MAY EXPERIENCE A SIGNIFICANT DISRUPTION OF OUR OPERATIONS. We encounter strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and production of, crude oil and natural gas. Competition is particularly intense with respect to the acquisition of desirable underdeveloped crude oil and natural gas properties. Many of our competitors have financial resources, staff and facilities substantially greater than ours. Although we believe the current operating resources available under our cash collateral order will be adequate to preclude any significant disruption of our operations in the immediate future, the continued availability of these materials and resources to us cannot be assured. 23 OUR COMMON STOCK IS NOT LISTED ON THE NASDAQ NATIONAL MARKET OR ANY OTHER STOCK EXCHANGE, WHICH MAY DEPRESS THE PRICE OF THE COMMON STOCK AND YOU MAY HAVE DIFFICULTIES RESELLING THE STOCK. Our common stock is not listed on the Nasdaq National Market or any other national securities exchange which may affect the liquidity and marketability of our common stock. OUR PROFITABILITY IS HIGHLY DEPENDENT ON INDUSTRY CONDITIONS THAT HAVE, IN THE PAST, CAUSED US TO IMPLEMENT SIGNIFICANT WRITE-DOWNS OF OUR ASSETS. Our revenue, profitability and future rate of growth substantially depend on prevailing prices for crude oil and natural gas. Crude oil and natural gas prices can be extremely volatile. Prices are also affected by actions of state and local agencies, the United States and foreign governments and international cartels. IF OIL PRICES DECLINE SIGNIFICANTLY, WE MAY HAVE TO WRITE DOWN THE CARRYING VALUE OF OUR RESERVES. We periodically review the carrying value of our crude oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, a ceiling test is performed whereby capitalized costs of proved oil and natural gas properties may not exceed a present value, based on unescalated prices at a single point in time, of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded. When a write-down is required, it results in a charge to earnings, but does not affect cash flow from operating activities. Once incurred, a write-down of crude oil and natural gas properties is not reversible at a later date. OUR ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUE INFORMATION MAY DIFFER FROM ACTUAL RESULTS WHICH COULD AFFECT OUR REPORTED ASSETS AND OUR ABILITY TO BORROW FUNDS. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve data included in our 2001 annual report on Form 10-K represent only estimates. In addition, the estimates of future net revenue from proved reserves and their present value are based on assumptions about future production levels, prices and costs that may change over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the present value of proved reserves for the crude oil and natural gas properties described in our 2001 annual report are based on the assumption that future crude oil and natural gas prices remain the same as crude oil and natural gas prices at December 31, 2001. The New York Mercantile Exchange prices as of December 31, 2001, used for purposes of our estimates were $19.84 per Bbl of crude and $2.57 per MMbtu of natural gas, respectively. Any significant variance in actual results from these assumptions we use could also materially affect the estimated quantity and value of our reserves. COSTS OF ENVIRONMENTAL LIABILITIES, REGULATION AND LITIGATION COULD EXCEED OUR ESTIMATES. Our current and former operations involve management of regulated materials and are subject to various environmental laws and regulations. These laws and regulations may obligate us to remediate various sites at which petroleum, chemicals, low-level radioactive substances or other regulated materials may have been disposed of or released. We have been party to legal proceedings involving environmental matters in the past. Although these legal proceedings were settled in connection with our plan of reorganization, there can be no assurance that we will not be party to other legal proceedings involving environmental matters in the future. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of: o the difficulty of estimating remediation costs; o the uncertainty in quantifying liabilities under environmental laws that may impose joint and several liability on all potentially responsible parties; and 24 o the nature of environmental laws and regulations. Although we believe we have established appropriate reserves for liabilities, including remediation costs, we could be required to set aside additional reserves in the future due to these uncertainties. ITEM 3. LEGAL PROCEEDINGS Bankruptcy Proceedings. On February 6, 2002, we and our consolidated subsidiaries, Coho Resources, Inc. and Coho Oil & Gas, Inc., filed a voluntary Chapter 11 petition in the United States Bankruptcy Court for the Northern District of Texas. Consistent with bankruptcy cases involving publicly traded companies and their affiliates, a number of proceedings have occurred since February 6, 2002, the most significant of which are discussed below. The bankruptcy court approved Fulbright & Jaworski L.L.P. as our counsel, CIBC World Markets Corp. as our financial advisor and Arthur Andersen LLP as our auditors for the year ended December 31, 2001. The bankruptcy court also approved our retention of ordinary course of business professionals. These professionals are assisting us in our efforts to reorganize our business and to continue our operations as debtor-in-possession. An official committee for the unsecured creditors has been formed by the Office of the United States Trustee. The bankruptcy court approved counsel for the Official Unsecured Creditors Committee. The bankruptcy court approved our use of cash collateral in the continued operations of our business, including its use in our capital expenditure programs. Our use of cash collateral has been approved through April 30, 2002. A budget for the next two month period (May and June 2002) will be submitted by April 1, 2002 for approval in April 2002. In February and March 2002, under the Order Authorizing Use Of Cash Collateral, we paid the bank group interest payments of $2.5 million and $823,000, respectively. We plan on making additional interest payments on a monthly basis. Immediately following the commencement of our bankruptcy case, we obtained permission from the bankruptcy court to pay working and royalty interest owners to ensure that payments to them were not interrupted. As a result, working and royalty interest owners will continue to receive all payments to which they are entitled throughout the pendency of our bankruptcy cases. Hicks Muse Lawsuits. We are the plaintiff in a lawsuit styled Coho Energy, Inc. v. Hicks, Muse, et al, which we filed in the District Court of Dallas County, Texas, 68th Judicial District on May 27, 1999. The lawsuit alleges (1) breach of the written contract terminated by HM4 Coho L.P. ("HM4"), a limited partnership formed by Hicks Muse on behalf of the Hicks, Muse, Tate & Furst Equity Fund IV, in December 1998, (2) breach of the oral agreements reached with HM4 on the restructured transaction in February 1999 and (3) promissory estoppel. We reached a settlement of the litigation in May 2001, subject to approval of the United States Bankruptcy Court (the "Bankruptcy Court") and resolution of certain disputes relating to a matter under seal by order of the Bankruptcy Court as discussed below. Final settlement documents were signed during October 2001 and approved by the Bankruptcy Court in January 2002. The disputed termination issue discussed below has not been finalized so the final settlement has been extended until April 15, 2002. We do not expect the settlement to have a material impact on our financial position or results of operations. Pursuant to our 2000 plan of reorganization, shareholders as of February 7, 2000, are eligible to receive their pro rata share of 20% of the proceeds available from the Hicks Muse lawsuit settlement after fees and expenses. We have not yet determined the impact, if any, of our current bankruptcy proceedings on the distribution of these proceeds to shareholders. During 2001, we became involved in a matter in connection with the lawsuit filed by us against Hicks Muse. This matter is under seal by order of the Bankruptcy Court. The matter involves a termination issue and the plaintiff claims damages that are based on a percentage of the ultimate amount recovered, if any, in the lawsuit against Hicks Muse. These percentages would be calculated on a graduated scale decreasing from 30% to 10% as the amount recovered increases. Alternatively, the plaintiff claims damages on the basis of lost time. However, we do not believe that either of these methods represents an appropriate measure of damages. We believe the claim is without merit. At the order of the Bankruptcy Court, certain matters were arbitrated. The arbitration panel's sealed findings 25 were forwarded to the Bankruptcy Court for consideration in conjunction with the final settlement discussed above. The damages awarded are currently being appealed by us and the plaintiff. We do not expect this matter to have a material impact on our financial position or results of operations. Resolution of this matter may, however, impact the amount of proceeds available to us from the settlement of the Hicks Muse lawsuit. On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of Hicks, Muse, Tate & Furst, filed a lawsuit in the United States District Court for the Northern District of Texas, Dallas Division, against certain of our former officers alleging, among other things, such officers made or caused to be made false and misleading statements as to the proved oil and gas reserves purportedly owned by us. The plaintiffs are asking for compensatory damages of approximately $15 million plus punitive damages. Subsequently, the plaintiff named Ryder Scott Company and Sproule Associates Inc., the independent petroleum consultants which evaluate our oil and gas reserves, as additional defendants. Pursuant to our bylaws, we may be required to indemnify such former officers against damages incurred by them as a result of the lawsuit not otherwise covered by our directors' and officers' liability insurance policy. The settlement of our lawsuit against certain affiliates of Hicks, Muse, Tate & Furst, as described above, requires dismissal of the claims against the former officers. If the suit continues against Ryder Scott Company and Sproule Associates Inc., we may be required to indemnify these companies subject to the terms contained in our agreements with them; however, we do not expect the ultimate outcome of this matter to have a material impact on our financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 26 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our common stock was, until June 7, 1999, listed on the Nasdaq Stock Market under the symbol "COHO." Our common stock is currently traded on the Nasdaq's OTC Bulletin Board under the symbol "CHOH." The following table shows the high and low sale prices of our common stock over recent periods. As a result of our recent filing of a voluntary petition for bankruptcy protection, the trading value of our common stock on March 28, 2002 was $.01.

As a result of our financial condition and decreases in the market value of our common stock during 1999, the Nasdaq Stock Market on March 8, 1999, suspended trading of our common stock. As of the close of business on June 4, 1999, our common stock was delisted from Nasdaq. As a result of these actions, our common stock is not currently listed but is trading over the counter. At March 25, 2002, there were 203 holders of record of our common stock. Prior to March 31, 2000, the effective date of the 2000 plan of reorganization, we had 25,603,512 shares of old common stock issued and outstanding. Old shareholders received shares of new common stock on a basis of one share of new common stock for 40 shares of old common stock on the effective date. We have never paid cash dividends on our existing common stock and we currently do not anticipate being able to pay cash dividends in the foreseeable future in light of our bankruptcy filing. Because Coho Energy, Inc. is a holding company, our ability to pay dividends depends on the ability of our subsidiaries to pay cash dividends or make other cash distributions. Our debt agreements generally prohibit the subsidiaries from paying dividends or making cash distributions. Any future dividends will depend on: o profitability; o financial condition; o cash requirements; o future prospects; o general business conditions; o the terms of our debt agreements; and o other factors our board of directors believes relevant. 27 ITEM 6. SELECTED FINANCIAL DATA The following selected consolidated financial data for each of the five years in the period ended December 31, 2001 are derived from, and qualified by reference to, our audited consolidated financial statements included in Item 8 of this Form 10-K. The information presented below should be read in conjunction with our consolidated financial statements and the related notes and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this Form 10-K. The selected consolidated financial data presented below is not necessarily indicative of the future results of our operations or financial performance.

(a) Amounts for 2000 and 2001 include interest expense of $36,192 and $35,476, respectively, and loss (gain) on standby loan embedded derivative of $15,163 and $(4,130), respectively, partially offset by interest income of $(448) and $(276), respectively. (b) Basic per share amounts have been computed by dividing net earnings after preferred dividends by the weighted average number of shares outstanding: 542 in 1997; 640 in 1998; 640 in 1999; 14,266 in 2000; and 18,714 in 2001. (c) Diluted per share amounts have been computed by dividing net earnings after preferred dividends by the weighted average number of shares outstanding including common stock equivalents, consisting of stock options and warrants, when their effect is dilutive: 558 in 1997; 640 in 1998; 640 in 1999; 14,266 in 2000; and 18,714 in 2001. (d) Amounts for 1998, 1999 and 2001 include $384,031, $388,685 and $282,845 respectively, related to the current portion of long-term debt. The working capital deficit as of December 31, 1999 also includes liabilities subject to compromise as a result of our 1999 bankruptcy filing. (e) Accumulated effect of an accounting change for 2001 relates to the adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." See "Managements Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations" for a discussion on accounting change. 28 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with our consolidated financial statements included in this Form 10-K. Some information contained in this Form 10-K, including information with respect to our plans and strategy for our business, are forward-looking statements. For more information about the limitations associated with these types of statements, see the section called "Forward-Looking Statements." GENERAL We have carried a high level of indebtedness since we reorganized and emerged from bankruptcy on March 31, 2000. Our total consolidated indebtedness is $308.0 million and our ratio of total consolidated indebtedness to total capitalization was 82% as of December 31, 2001. Our major borrowings are comprised of $195 million under a senior revolving bank credit facility and $93.5 million under senior subordinated notes due 2007 that were issued mainly to our majority shareholders and herein referred to as the standby loan. Interest owned under our standby loan is currently required to be "paid-in-kind" by increasing the amount of the principal outstanding through the issuance of additional standby notes. In April 2001, we entered into an agreement with JP Morgan, a division of Chase Securities, to act as our financial advisor in evaluating various strategic transactions including potential recapitalization transactions or the sale of all or a portion of our company. Although we entered into negotiations with a third party for the sale of our Mississippi oil and gas assets in September and October 2001, we were not able to complete the sale. On November 1, 2001, the lenders under our senior revolving bank credit facility notified us that our borrowing base under this facility had been reduced from $195 million to $175 million effective November 1, 2001. On November 2, 2001, we received a notice of borrowing base deficiency because borrowings under the credit facility exceeded the redetermined borrowing base by $20 million. Under the credit facility, we could have remedied the borrowing base deficiency by providing additional collateral sufficient to eliminate the borrowing base deficiency or by making a cash payment sufficient to eliminate the borrowing base deficiency. Currently, all of our assets are pledged as collateral under the credit facility and we did not have sufficient working capital to make a cash payment to eliminate the borrowing base deficiency within the 90 day cure period. On February 1, 2002, we received a notice of default under the credit facility and subsequently filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code as discussed below. SUBSEQUENT EVENT - BANKRUPTCY PROCEEDINGS On February 6, 2002, we and our wholly owned subsidiaries, Coho Resources, Inc. and Coho Oil & Gas, Inc., filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Northern District of Texas. The bankruptcy petitions were filed to protect us while we develop a solution to our liquidity problems. We are currently operating as debtor-in-possession under the court's supervision and pursuant to its orders. We filed schedules with the bankruptcy court on March 8, 2002. Those schedules contain our unaudited, and in some cases, estimated assets and liabilities as of February 6, 2002, as shown by our accounting records. Under our cash collateral order, we have agreed with the lenders under the senior credit facility to develop a marketing plan with our new financial advisor, CIBC, for the sale of our assets or a recapitalization of our debt and equity. We, together with CIBC, are currently working with our bank group and the unsecured creditors committee on mutually acceptable terms for this marketing plan to achieve maximum value for our assets in this process. We expect that once finalized and approved, the marketing plan will allow us to explore other alternatives available to us, in addition to a sale of our assets, including a recapitalization of our debt and equity assuming we are able to raise sufficient equity from existing or new investors to cure the $20 million borrowing base deficiency and to provide working capital to develop our properties. A recapitalization may include a partial sale of our assets. Any sale or recapitalization will be subject to bankruptcy court approval under a Chapter 11 plan of reorganization or liquidation or in accordance with Section 363 of the bankruptcy code. 29 At this time, it is not possible to predict the outcome of the bankruptcy proceedings, in general, or the effect on our business or on the interests of the creditors or shareholders. We believe, however, that it may not be possible to satisfy in full all of the claims against us. In addition, the shareholders of our company may not realize any value on their investment. As a result of the bankruptcy filing, all of our liabilities incurred prior to February 6, 2002, including secured debt, are subject to compromise. Under the bankruptcy code, payment of these liabilities may not be made except pursuant to a plan of reorganization or liquidation or bankruptcy court approval. No adjustments to the carrying value of our assets or liabilities related to the bankruptcy filing have been reflected in our December 31, 2001 balance sheet. In accordance with SOP 90-07, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code", during 2002, we will adjust liabilities subject to compromise to our estimate of the allowed claims. Accordingly, during 2002, we will write-off unamortized debt issuance costs and debt discounts of $22.6 million and $10.7 million, respectively. These adjustments to the December 31, 2001, carrying values will be recorded in earnings as reorganization items. In addition, we will record the prepayment penalty ($30.8 million at December 31, 2001) and adjust the recorded amount of the standby loan embedded derivative, based on the estimated allowed claims during 2002. Subsequent to February 6, 2002, we filed two motions with the bankruptcy court to seek use of the bank group's cash collateral on an on-going basis. Since filing bankruptcy, we have been operating under two orders authorizing the use of cash collateral, initially an interim order and currently a final order which was approved on February 26, 2002 and authorizes expenditures through April 30, 2002. Under these orders, we may pay for ordinary course of business goods and services incurred after February 6, 2002 that are within the court approved budgets attached to each order. Any expenditure that is outside the ordinary course of business or that is not reflected in the approved budgets must be specifically approved by the bankruptcy court. CRITICAL ACCOUNTING POLICIES AND ESTIMATES Our discussion and analysis of our financial condition and results of operation are based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles as presently established in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, equity, revenues and expenses. We prepare our estimates, including those related to oil and gas revenues, bad debts, oil and gas properties, crude oil and natural gas reserves, embedded derivative fair values, contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe our more significant judgments and estimates affect the following critical accounting policies used in the preparation of our consolidated financial statements. See Note 1 to the Consolidated Financial Statements for a complete list of significant accounting policies. Crude Oil and Natural Gas Properties. We have used the full-cost method of accounting for our investment in crude oil and natural gas properties. In accordance with generally accepted accounting principles, at a point in time coinciding with the quarterly and annual reporting periods, we must test the carrying value of our crude oil and natural gas properties, net of related deferred taxes, against the "cost center ceiling." The "cost center ceiling" is a calculated amount based on estimated reserve volumes valued at then-current realized prices held flat for the life of the properties discounted at 10% per annum plus the lower of cost or estimated fair value of unproved properties. If the carrying value exceeds the cost center ceiling, the excess must be expensed in that period and the carrying value of the oil and gas reserves lowered accordingly. Amounts required to be written off may not be reinstated for any subsequent increase in the cost center ceiling. Management's assumptions used in calculating oil and natural gas reserves or regarding the future cash flows or fair value of our properties are subject to change in the future. Any change could cause impairment expense to be recorded, reducing our net income and our basis in the related asset. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. There can be no assurance that the proved reserves will be developed within the periods estimated or that prices and costs will remain constant. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, the amount of calculated reserves change. 30 Depletion and depreciation expense is also directly affected by our reserve estimates. Any change in reserves directly impacts the amount of depletion and depreciation expense we recognize in a given period. Assuming no other changes, such as an increase in depreciable base, as our reserves increase, the amount of depletion and depreciation expense in a given period decreases and vice versa. Changes in future commodity prices would likely result in increases or decreases in estimated recoverable reserves. Bad Debt Expense. We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. Many of our receivables are from joint interest owners on property of which we are the operator. Thus, we may have the ability to withhold future revenue disbursements to cover any non-payment of joint interest billings. Our crude oil and natural gas receivables quickly turnover, usually one month for oil and two months for gas; thus, signaling any problem accounts in a timely manner. This review of receivables is dependent on the judgment of management. If it is determined that the carrying value of a receivable might not be recoverable, we record an allowance to the extent we believe the receivable is not recoverable. Embedded Derivatives. We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" effective January 1, 2001, as more fully discussed under "Hedging Activities and Other Derivatives." SFAS 133 requires us to recognize all derivative instruments (including embedded derivatives) on the balance sheet at fair value. We estimate the fair value of the embedded derivatives contained in our standby loan agreement and certain lease agreements based on future crude oil and natural gas price curves, historical crude oil and natural gas volatility and estimated discount rates. Actual future prices may not equal the estimated amounts and significant fluctuations in earnings could result as prices increase or decrease from the price estimates used in estimating the fair value of these embedded derivatives. During 2002, subsequent to our bankruptcy filing, we will adjust the recorded amount of the standby loan embedded derivative based on the estimated allowed claim as previously discussed under "Subsequent Event - Bankruptcy Proceedings." Revenue Recognition Policy. We recognize revenue from the sale of crude oil and natural gas in the period delivered. LIQUIDITY AND CAPITAL RESOURCES Capital Sources. During 2001, cash flow provided by operating activities was $24.4 million compared with $9.9 million for the same period in 2000. Operating revenues, net of lease operating expenses, production taxes and general and administrative expenses, decreased $12.2 million from $53.7 million in 2000 to $41.5 million in 2001, primarily due to: o realized crude oil price decreases of 17% between such comparable periods; o decreases in natural gas production; and o increases in operating expenses. These decreases were partially offset by: o increases in crude oil production; o decreases in production taxes; and o decreases in general and administrative expenses. Cash flow provided by operating activities also included $10.9 million in reorganization costs (excluding a $1.1 million Tunisian impairment) in 2000 and $21.4 million in interest expense on our old and new bank credit facilities in 2000 as compared to a reduction of $3.2 million in reorganization costs and $14.8 million in interest expense on our credit facility during 2001. Changes in operating assets and liabilities resulted in $4.6 million of cash used for operating activities for 2001, compared to $11.7 million of cash used for operating activities for the same period in 2000. See "Results of Operations" for a discussion of operating results. 31 Working Capital. We had a working capital deficit of $284.1 million at December 31, 2001 compared to a working capital deficit of $2.6 million at December 31, 2000. The decrease in working capital primarily relates to an increase of $281.8 million in current portion of long term debt and an increase of $11.8 million in accrued unrealized losses on embedded derivatives due to our default under our senior revolving credit facility in February 2002 and a decrease of $3.3 million in accounts receivable. These decreases in working capital are partially offset by several factors including the following: o an increase of $2.1 million in cash and cash in escrow; o an increase of $2.4 million in other current assets, primarily related to accrued unrealized gains on derivatives due to the adoption of SFAS. No. 133; o a decrease of $3.1 million in accrued operating costs; o a decrease of $2.7 million in accrued interest payable; o a decrease of $2.0 million in accrued reorganization costs; o a decrease of $1.1 million related to environmental claims; o a decrease of $895,000 in accrued hedging losses; o a decrease of $415,000 in trade payables; and o a decrease of $690,000 in various other accrued liabilities. Credit Facilities. We, and some of our subsidiaries, were parties to an old bank group loan agreement prior to March 31, 2000. Borrowings outstanding under the old bank group loan, together with accrued interest and reasonable fees totaling $260.2 million, were paid on March 31, 2000. We obtained the funds necessary for the payment of the old bank group loan through the combination of borrowings under the new senior revolving credit facility, borrowings under the standby loan and from cash on hand. Additionally, we owed approximately $162 million of principal and accrued interest under our old bond indenture. Under the plan of reorganization, these old bonds and accrued interest were converted into 15,362,107 shares of new common stock. The existing senior revolving credit facility was obtained from a syndicate of lenders led by JPMorgan Chase Bank, as agent for the lenders, and has a maximum loan commitment amount of up to $250 million through March 31, 2003. The credit facility limits advances to the amount of the borrowing base, which is subject to semiannual borrowing base redeterminations each April 1 and October 1, based on the Company's reserve reports and will be made at the sole discretion of the lenders. We, or Chase, may each request one additional borrowing base redetermination during any calendar year. The April 1, 2001 redetermination resulted in a decrease in our borrowing base from $205 million to $195 million. As discussed more fully under "General", on November 1, 2001, the lenders under the senior revolving credit facility notified us that our borrowing base under this facility had been redetermined in the semiannual review from $195 million to $175 million effective November 1, 2001. We were unable to cure the $20 million borrowing base deficiency within the 90 day cure period and we received a notice of default under the facility on February 1, 2002. At December 31, 2001, the outstanding advances of $195 million under the senior revolving credit facility were classified as a current liability due to the default under the credit facility. Interest on advances under the credit facility are payable on the earlier of the expiration of any interest period under the credit facility or quarterly. Amounts outstanding under the credit facility accrue interest at our option at either the Eurodollar rate, which is the annual interest rate equal to the London interbank offered rate ("LIBOR") for deposits in United States dollars that is determined by reference to the Telerate Service or offered to Chase plus an applicable margin (currently 3%), or the prime rate, which is the floating annual interest rate established by Chase 32 from time to time as its prime rate of interest plus an applicable margin (currently 2%). In the event any principal is not paid when due, whether at maturity or upon acceleration, interest will accrue at the applicable rate, as discussed above, plus 2%. Subsequent to filing a voluntary petition for protection under the bankruptcy code on February 6, 2002, we have been operating under a cash collateral order. Pursuant to the cash collateral order, interest will accrue at the LIBOR rate plus the applicable margin (currently 3%) plus the 2% default rate until March 15, 2002 on borrowings of $20 million and until May 13, 2002 on borrowings of $175 million. Subsequent to these periods interest will accrue at prime plus the applicable margin (currently 2%) plus the 2% default rate. The credit facility has been secured by granting Chase the following collateral for the benefit of the lenders: o first and prior security interests in the issued and outstanding capital stock and other equity interests of our material subsidiaries; o first and prior mortgage liens and security interests covering proved mineral interests selected by Chase having a present value, as determined by Chase, of not less than 85% of the present value of all our proved mineral interests evaluated by the lenders for purposes of determining the borrowing base; and o first and prior security interests in our other tangible and intangible assets. The credit agreement contains financial and other covenants including: o maintenance of required ratios of cash flow to interest expense paid or payable in cash (not less than 2.75 to 1 for the average of the last four consecutive quarters most recently ended December 31, 2001; and 3.0 to 1 for the average of the last four quarters for any quarter ending after January 1, 2002), senior debt to cash flow required (not to exceed 3.75 to 1 for the average of the last four quarters most recently ended December 31, 2001; and 3.5 to 1 for the average of the last four consecutive quarters for any quarter ending after January 1, 2002), and current assets (including unused borrowing base) to current liabilities required (throughout the term of the credit agreement, to be not less than 1 to 1 as of the end of each quarter); o restrictions on the payment of dividends; and o limitations on the incurrence of additional indebtedness, the creation of liens and the incurrence of capital expenditures. We were unable to maintain the required ratio of senior debt to cash flow and current assets to current liabilities, as required by the credit agreement during the fourth quarter of 2001. We believe that we were in compliance with all other covenants under the credit facility at the end of the fourth quarter of 2001. As of December 31, 2001, the covenant ratios of cash flow to interest expense, senior debt to cash flow, and current assets to current liabilities were 2.79 to 1, 4.7 to 1, and .06 to 1, respectively. Non-cash transactions resulting from the adoption and accounting treatment of SFAS No. 133 are excluded from the calculation of covenant ratios under the credit facility. As previously discussed, as of February 1, 2002, we are in default under the credit agreement. Accordingly, the entire balance outstanding at December 31, 2001, has been classified as a current liability. The standby loan was made under a senior subordinated note facility under which we issued $72 million of senior subordinated notes to PPM America, Inc., Appaloosa Management, L.P., Oaktree Capital Management, L.L.C., Pacholder Associates, Inc. and their respective assignees, herein referred to as the "standby loan". At December 31, 2001, an aggregate amount of $93.5 million in senior subordinated notes was outstanding under the standby loan. Our rights and responsibilities and those of the standby lenders are governed by a standby loan agreement dated March 31, 2000. Debt under the standby loan agreement is evidenced by notes maturing March 31, 2007 and bearing interest at a minimum annual rate of 15% and payable in cash semiannually. After March 31, 2001, additional semiannual interest payments are payable in an amount equal to 1/2% for every $0.25 that the "actual price" (as described below) for our oil and gas production exceeds $15 per barrel of oil equivalent during the applicable semiannual interest period, up to a maximum of 10% additional interest per year. Any time the average realized price exceeds $20 per barrel of oil equivalent, we will have to pay the 10% maximum additional interest. The "actual price" for 33 our oil and gas production is the weighted average price received by us for all our oil and gas production, including hedged and unhedged production, net of hedging costs, in dollars per barrel of oil equivalent using a 6:1 conversion ratio for natural gas. The actual price will be calculated over a six-month measurement period ending on the date two months before the applicable interest payment date. Additionally, upon an event of default occurring under the standby loan, interest will be payable in cash, unless otherwise required to be paid-in-kind, at a rate equal to 2% per year over the applicable interest rate. The semiannual interest payments under the standby loan are required to be paid-in-kind subject to the requirements of the intercreditor arrangement between the standby lenders and the lenders under the new credit agreement unless we meet specified financial tests. "Paid-in-kind" refers to the payment of interest owed under the standby loan by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. The semiannual standby loan interest payments in the amount of $5.8 million, due on March 30, 2001 were paid-in-kind and were reflected at issuance as an increase in long term debt and long term derivative liabilities of $4.4 million and $1.4 million, respectively. The standby loan interest payments of $10.3 million, which were at the maximum rate of 25%, were paid-in-kind when due on September 28, 2001, and were reflected at issuance as an increase in long term debt and long term derivative liabilities of $8.3 million and $2.0 million, respectively. Previously, interest accruing on the standby loan, subsequent to the previous semiannual interest payment was reflected in long term debt until the next semiannual interest was paid in cash or paid-in-kind; however, due to the default under the standby loan agreement, as discussed below, accrued interest at December 31, 2001 was classified as a current liability. Payment of the standby loan notes is expressly subordinate to payments in full in cash of all obligations arising in connection with the credit facility. After the initial 12-month period, cash interest payments may be made only to the extent by which EBITDA, or earnings before interest, tax, depreciation and amortization expense, on a trailing four-quarter basis exceed $65 million. The credit agreement also prohibits us from making any cash interest payments on the standby loan indebtedness if the outstanding indebtedness under both the credit facility and the standby loan exceeds 3.75 times EBITDA for the trailing four quarters. We do not currently meet and have not met in the past the requirements to make cash interest payments on the standby loan indebtedness. We may prepay, or may be required to repay, under certain circumstances, the standby loan notes at the face amount, in whole or in part, in minimum denominations of $1,000,000, plus either a standard make-whole payment at 300 basis points over the "treasury rate" for the first four years, beginning in the fifth year, a prepayment fee of 7.5% of the principal amount being prepaid; in the sixth year, a prepayment fee of 3.75% of the principal amount being prepaid; and after the sixth year there is no prepayment fee. The "treasury rate" is the yield of U.S. Treasury securities with a term equal to the then-remaining term of the standby loan notes that has become publicly available on the third business day before the date fixed for repayment. As of December 31, 2001, the prepayment fee for the then total outstanding principal amounts, using then current treasury rates, was approximately $30.8 million, bringing the total obligation under the standby loan, including the prepayment fee and accrued interest, to approximately $127.9 million. The standby loan agreement contains certain covenants and cross default provisions, including cross default provisions which automatically cause us to be in default under the terms of the standby loan agreement in the event we are in default under the senior revolving credit facility or in the event we seek relief under any provision of the bankruptcy law. In the event of default, the standby lenders may declare all amounts due under the standby loan agreement immediately due, unless the default is due to bankruptcy proceedings, which will automatically accelerate all amounts due, including principal, accrued interest and the prepayment fee. On February 1, 2002, we received a notice of default under the senior revolving credit facility. This default automatically caused us to be in default under the standby loan agreement. On February 6, 2002, we filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code which automatically accelerated all amounts due, including the prepayment fee, under the standby loan. Due to the default under the standby loan agreement, the carrying value of our outstanding debt at December 31, 2001 was classified as a current liability. The prepayment fee was not payable until we defaulted under the standby loan agreement during February 2002; therefore, it has not been recorded on our balance sheet as of December 31, 2001. Dividends. It is unlikely that we will pay dividends in the foreseeable future in light of our bankruptcy filing. Additionally, the terms of the new credit facility and the standby loan restrict our paying dividends. 34 Capital Expenditures. During 2001, we incurred capital expenditures of $33.2 million compared with $25.3 million for the same period in 2000. We spent approximately $17.0 million in our Mississippi fields and $16.2 million in our Oklahoma fields during 2001. We drilled 35 wells, as listed below, and continued our development efforts through recompletions and workovers on existing wells and initiation or expansion of waterflood projects within the field. We also participated in the drilling of seven gross wells (.2 net wells) that were completed on two outside operated Oklahoma properties. Following are the wells drilled during 2001: Mississippi Fields: Brookhaven - 1 dry hole Cranfield - 1 producing gas Martinville - 2 producing oil Soso - 2 producing oil Oklahoma Fields: Tatums - 10 producing oil; 5 service wells; 1 dry hole East Fitts - 3 producing oil; 1 suspended drilling Jennings-Deese - 2 producing oil; 3 service wells Eola - 3 producing oil; 1 dry hole Non-operated - 7 producing oil

A $12 million capital expenditures budget for the year 2002 has been approved by our board of directors, which will be funded by working capital from operations. As discussed in "Subsequent Event - Bankruptcy Proceedings", we have filed for relief under Chapter 11 of the United States Bankruptcy Code and future capital expenditures will be subject to expenditure constraints imposed by the bankruptcy court. Subsequent to the bankruptcy filing, a Final Order Authorizing Use of Cash Collateral has authorized capital expenditures of approximately $1.0 million per month through April 30, 2002, at which time we expect the cash collateral order to be amended to approve a similar capital expenditure level for future months. We have no material capital commitments related to our operations and are consequently able to adjust the level of our expenditures based on available cash flow. General and administrative costs associated with our exploration and development activities of $960,000 were capitalized for 2000 compared with $765,000 of capitalized costs for 2001. Due to the significantly reduced budget for 2002, we expect to reduce the amount of capitalized G&A to $300,000 during 2002. Hedging Activities and Other Derivatives. Crude oil and natural gas prices are subject to significant seasonal, political and other variables which are beyond our control. In an effort to reduce the effect of the volatility of the prices received for crude oil and natural gas, we have entered, and expect to continue to enter, into crude oil and natural gas hedging transactions by entering into certain arrangements that fix a minimum and maximum price range per barrel. We entered into these arrangements to reduce the downside risk associated with potential crude oil and natural gas price declines by setting a floor price for our future production based on the New York Mercantile Exchange crude oil and natural gas prices. Due to working capital constraints, we entered into the "costless collar" type of transactions because they do not require upfront premiums. Additionally, our bank credit facility required us to hedge 75% of our crude oil production as of March 31, 2000 within ten days of such date for a two-year period. The bank credit facility also limits our hedging to 85% of crude oil production. While our hedging program is intended to stabilize cash flow and thus allow us to plan our capital expenditure program with greater certainty, any hedging transactions may limit our potential gains if crude oil and natural gas prices rise substantially over the price established by the hedge. Because all hedging transactions are tied directly to our crude oil and natural gas production, we do not believe that these transactions are of a speculative nature. The amount we receive or pay on our crude oil hedging transactions is determined as the difference between the contract price and the average closing price for West Texas Intermediate crude oil on the NYMEX for the contract period. The amount we receive or pay on our natural gas hedging transactions is generally determined as the difference between the contract price and the New York Mercantile Exchange Henry Hub settlement price the next to last business day of the contract. Hedging activities do not affect the actual price received for our crude oil and natural gas sold. Effective January 1, 2002, we dedesignated the hedging relationship for the remainder of our hedges. Accordingly, all future unrealized gains and losses on our derivatives will be recognized through earnings. Net unrealized gains of $2.0 million as of December 31, 2001, which are included in other comprehensive income will be recognized in earnings over the original hedge period. 35 Based on fourth quarter 2001 production levels, 36% of our 2002 crude oil production has been hedged as follows: Minimum and Maximum Crude Oil Price Arrangements. o 500 barrels per day for the period January 1, 2002 to December 31, 2002, with a minimum price of $22.00 and a maximum price of $28.00. o 500 barrels per day for the period January 1, 2002 to December 31, 2002, with a minimum price of $22.00 and a maximum price of $29.60. o 500 barrels per day for the period January 1, 2002 to December 31, 2002, with a minimum price of $24.00 and a maximum price of $28.60. o 500 barrels per day for the period April 1, 2002 to December 31, 2002, with a minimum price of $22.50 and a maximum price of $26.45. o 500 barrels per day for the period April 1, 2002 to December 31, 2002, with a minimum price of $22.50 and a maximum price of $25.50. Fixed Price Crude Oil Arrangements. o 5,500 barrels per day for the period January 1, 2002 to March 31, 2002 with a fixed price of $20.40. We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" effective January 1, 2001. The Statement required us to recognize all derivative instruments (including certain derivative instruments embedded in other contracts) on the balance sheet as either an asset or liability based on fair value on January 1, 2001. Subsequent changes in fair value for the effective portion of derivatives qualifying as hedges are recognized in other comprehensive income until the hedged item is recognized in earnings, at which time changes in fair value previously recognized in other comprehensive income are reclassified to earnings. Subsequent changes in fair value for the ineffective portion of derivatives qualifying as hedges and for derivatives that do not qualify as hedges are adjusted to fair value through earnings. Our standby loan agreement, as discussed above under "Credit Facilities", contains an additional semiannual interest feature which is calculated based on the actual price we receive for our oil and gas production and certain lease agreements contain provisions for additional lease payments based on certain crude oil prices. The additional interest feature of the standby loan agreement and the additional lease payment feature of the lease agreements are considered embedded derivatives under SFAS No. 133. These embedded derivatives were recorded as liabilities based on fair value on January 1, 2001 and subsequent changes in fair value are recorded through earnings. Discontinuation of Tunisian Operations. We decided to discontinue our participation in the exploration of two Tunisia, North Africa permits due to capital commitments during 2001 exceeding $7 million net to our interest. The two subsidiaries, Coho Anaguid, Inc. and Coho International Limited, that own these permits filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001. During May 2001, Coho International entered into a settlement agreement with the other joint owners in the permit area. Under this agreement, Coho International assigned its interest in the Fejaj permit to the other joint owners in exchange for the assumption by the other joint owners of Coho International's existing obligations and existing payables under the permit. During July 2001, Coho Anaguid, Inc. entered into a definitive agreement to sell all of its interest in the Anaguid permit to Pioneer Natural Resources Company and the other joint owners in the permit area for cash proceeds of approximately $200,000 and the assumption of Coho Anaguid's obligations under the permit totaling in excess of $7 million. These sales agreements have been approved by the United States Bankruptcy Court and the Tunisian government. We converted the bankruptcy proceedings for Coho Anaguid and Coho International from Chapter 11 reorganization proceedings to Chapter 7 liquidation proceedings during the first quarter of 2002 to wind 36 down these proceedings. We have not recorded the liabilities subject to compromise for these subsidiaries in our consolidated balance sheet as of December 31, 2001 because these liabilities are solely obligations of the bankrupt subsidiaries and, furthermore, substantially all of the obligations of these subsidiaries will be assumed under the sales agreements. RESULTS OF OPERATIONS SELECTED OPERATING DATA

2001 COMPARED WITH 2000 Operating Revenues. During 2001, production revenues decreased 15% to $77.0 million as compared to $90.2 million in 2000. This decrease was principally due to a 17% decrease in the price received for crude oil, including hedging losses discussed below, a 1% decrease in the price received for natural gas, including hedging losses discussed below, and a 22% decrease in natural gas production, partially offset by a 5% increase in crude oil production. During 2001, we experienced a 5% increase in daily crude oil production as compared to 2000 due to returning wells to production which were previously not producing due to depressed crude oil prices making it uneconomical to produce or repair such wells and due to increased drilling activity on our operated properties. These increases were partially offset by normal production declines, primarily on our Mississippi crude oil properties and production decreases on our properties which are operated by third parties. The 22% decrease in daily natural gas production during 2001 is due to production declines on our operated Oklahoma and Mississippi gas properties and non-operated Oklahoma gas properties. The decline between the comparable periods is primarily due to several recompletions during late 1999 and early 2000 on our Oklahoma properties which experienced high initial production but subsequently experienced rapid production declines and normal production declines on our Mississippi properties. Average crude oil prices (net of hedging losses discussed below) decreased 17% during 2001 compared to the same period in 2000. We experienced a $5.44 per Bbl decrease in the actual price received from the sale of our 37 crude oil which was partially offset by a price increase of $1.38 per Bbl due to a reduction in crude oil hedging losses between the comparable periods. Substantially all of our Mississippi crude oil is sold under contracts which are based on posted crude oil prices and substantially all of our Oklahoma crude oil is sold under a contract which is based on the New York Mercantile Exchange price. The price per Bbl received is adjusted for the quality and gravity of the crude oil and is generally lower than the NYMEX price. Our overall average crude oil price received during 2001 was $20.66 per Bbl, before hedging losses of $1.41 per Bbl as discussed below, which represented a discount of 20% to the average NYMEX price for such period. Our realized price for our natural gas decreased 1% from $3.73 per Mcf in 2000 to $3.68 per Mcf in 2001, including hedging losses of $.26 per Mcf and $.70 per Mcf, respectively, as discussed below. The fluctuations in the prices for natural gas are due to market supply and demand and due to current events which influence market perceptions of supply and demand. Production revenues for 2001 included crude oil hedging losses of $5.2 million ($1.41 per BOE) and natural gas hedging losses of $1.1 million ($.70 per Mcf) as compared to crude oil hedging losses of $9.9 million ($2.79 per BOE) and natural gas hedging losses of $544,000 ($0.26 per Mcf) for 2000. Expenses. Production expenses were $25.1 million for 2001 compared to $23.5 million for 2000. The increase in expenses from 2000 to 2001 is primarily due to increased electrical costs of approximately $1.9 million due to greater fluid movement and higher electrical rates which generally fluctuate with changes in crude oil and natural gas prices. Production taxes decreased $931,000 or 16% to $4.8 million during 2001 as compared to $5.8 million during 2000. This decrease is primarily due to lower crude oil prices and reinstatement of certain severance tax exemptions due to lower prices on our Mississippi crude oil production. On a BOE basis, production taxes decreased 18% to $1.22 per BOE during 2001 as compared to $1.49 per BOE during 2000 due to lower realized crude oil prices. General and administrative costs decreased $1.7 million or 24% between the comparable periods. This decrease is primarily due to: o reductions of $932,000 in employee-related costs primarily due to staff attrition and the termination of corporate office employees and officers in April 2000; o reductions of $538,000 in franchise taxes due to refunds for the year 2000 and reductions of over accrued amounts in 2001; o capitalization of $960,000 of salaries and salary related costs associated with exploration and development during 2001 as compared to $765,000 during the same period in 2000; and o increases in cost recoveries from working interest owners of $604,000 during 2001 as compared to 2000 due to an increase in well activity. 38 These decreases were partially offset by increases of $605,000 in professional fees. Interest expense decreased 2% to $35.5 million in 2001 as compared to $36.2 million in 2000. The following is a summary of interest expense between comparable periods:

The decrease for the comparable periods relates to several factors including the following: o lower interest expense due to a reduction in our debt on March 31, 2000 resulting from the reorganization; o higher interest rates and interest rates on our old bank loan during the first quarter of 2000 due to payment defaults and debt acceleration; o interest on past due interest payments on our old bank group loan during the first quarter of 2000; and o lower interest rates on our bank debt during 2001 resulting from overall lower market rates. These decreases were partially offset by: o an effective interest rate of 18.04% on the original $72 million standby loan issued March 31, 2000; o an effective rate of 24.42% on the paid-in-kind interest standby loans during 2001; o higher debt issuance amortization expense resulting from $33.9 million in debt issuance costs on our new debt; o amortization costs of $1.6 million during 2001 related to the standby loan original issue discount which resulted from the adoption of SFAS 133; and o no accrual of interest on our old unsecured bonds during the first quarter 2000 as a result of our bankruptcy filing. Approximately $3.5 million of additional interest expense would have been recognized during 2000 if not for the discontinuance of such interest accrual due to our bankruptcy. The average interest rate on outstanding indebtedness, excluding interest expense related to the embedded derivative, was 13.28% in 2001, compared to 12.48% in 2000. 39 Gain on standby loan embedded derivative for the year ended December 31, 2001 of $4.1 million represents the change in the fair value of the embedded derivative during the year excluding the effect of the payment of additional contingent interest and the issuance of new standby loan notes as follows:

Depletion and depreciation expense increased 16% to $17.8 million in 2001 from $15.3 million in 2000. This increase is primarily the result of increased production volumes and an increased depletion and depreciation rate per BOE, which was $4.50 in 2001, compared with $3.94 in 2000. The depletion and depreciation rate per BOE increased due to an increase in depletable costs and due to a decline in total proved reserves. During the fourth quarter of 2001, we reclassified unproved property costs totaling $30.6 million that had been excluded from depletable costs as of December 31, 2000 to costs subject to depletion at December 31, 2001. These costs were reclassified because most unproved projects will not be performed in the foreseeable future due to capital constraints and additionally, certain of the unproved projects are no longer viewed as economically attractive by our management team. See "Item 2. Business and Properties - Oil and Gas Operations-Reserves" for a discussion of the decline in total proved reserves. We have used the full-cost method of accounting for our investment in crude oil and natural gas properties as more fully discussed under "Critical Accounting Policies and Estimates". If the carrying value exceeds the cost center ceiling, the excess must be expensed in that period and the carrying value of the oil and gas reserves lowered accordingly. Amounts required to be written off may not be reinstated for any subsequent increase in the cost center ceiling. No writedowns of this kind were required on our United States properties in 2001 or 2000. We decided to discontinue our participation in the exploration of two Tunisia, North Africa permits due to capital commitments during 2001 exceeding $7 million net to our interest. The two subsidiaries, Coho Anaguid, Inc. and Coho International Limited, that own these permits filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001. During May 2001, Coho International entered into a settlement agreement with the other joint owners in the permit area. Under this agreement, Coho International assigned its interest in the Fejaj permit to the other joint owners in exchange for the assumption by the other joint owners of Coho International's existing obligations and existing payables under the permit. During July 2001, Coho Anaguid, Inc. entered into a definitive agreement to sell all of its interest in the Anaguid permit to Pioneer Natural Resources Company and the other joint owners in the permit area for cash proceeds of approximately $200,000 and the assumption of Coho Anaguid's obligations under the permit totaling in excess of $7 million. These sales agreements have been approved by the United States Bankruptcy Court and the Tunisian government. We converted the bankruptcy proceedings for Coho Anaguid and Coho International from Chapter 11 reorganization proceedings to Chapter 7 liquidation proceedings during the first quarter of 2002 to wind down these proceedings. We have not recorded the liabilities subject to compromise for these subsidiaries in our consolidated balance sheet as of December 31, 2001 because these liabilities are solely obligations of the bankrupt subsidiaries and, furthermore, substantially all of the obligations of these subsidiaries were assumed under the sales agreements. Reorganization costs reflected a gain of $3.2 million in 2001 as compared to $12.0 million in 2000. During 2000, substantially all estimated reorganization expenses were accrued, which included: o professional fees for consultants and attorneys assisting in the negotiations associated with reorganization alternatives and approval and implementation of our plan of reorganization; o termination benefits for severed employees; o payments and accrual of settlement amounts for officer employment agreements and officer severance agreements which were rejected in the plan of reorganization; 40 o payments and accrual of amounts made under our retention bonus plan; and o provisions for settlements of disputed bankruptcy claims and other costs to effect the plan of reorganization. During 2001, resolution of claims and settlements of disputed bankruptcy claims resulted in lower settlement amounts than originally estimated, resulting in a $2.2 million gain. In addition, our insurer agreed upon a claims settlement for reimbursement of litigation fees, resulting in a $950,000 gain. Accumulated effect of an accounting change for 2001 relates to the adoption of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 required us to record the fair value at January 1, 2001 of embedded derivatives contained in certain agreements on the balance sheet with an offsetting amount in accumulated effect of an accounting change. At January 1, 2001, we recorded the fair value of embedded derivatives for certain leases in Laurel, Mississippi and the standby loan resulting in a $300,000 loss and $9.5 million gain, respectively. The accumulated effect of the accounting change related to the standby loan embedded derivative was an increase in net income of $9.5 million because, under the previous accounting treatment, the changes in the estimated future additional interest due to changes in forecasted crude oil and natural gas prices were recorded on an undiscounted basis through earnings as compared to the fair market value basis under SFAS No. 133 that considers the time value of the future additional interest payments. Loss on extinguishment of debt of $4.4 million for 2000 resulted from the settlement of the old bank group and bondholders' claims. The loss on settlement of the old bank group claim was $303,000 and represents the difference in our carrying value of the debt and the cash settlement amount. The loss on settlement of the bondholders' claims was $4.1 million and represents the difference in our carrying value of the debt and the reorganization value of $10.52 per share for the common stock received by the bondholders. Our net operating loss carryforwards for United States and Canadian federal income tax purposes were approximately $154.7 million at December 31, 2001 and expire between 2003 and 2021. Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," requires that the tax benefit of those net operating loss carryforwards be recorded as an asset to the extent that management assesses the utilization of those net operating loss carryforwards to be more likely than not. A valuation allowance has been established for the entire net deferred tax asset balance of these net operating loss carryforwards as it is uncertain whether they will be used before they expire. During 2000, we experienced an "ownership change" (within the meaning of IRC section 382) on the effective date of the plan of reorganization as a result of the issuance of new common stock to certain holders of claims. Our ability to use any pre-effective date NOLs and capital loss carryovers to offset income in any post-effective date taxable year (and in the portion of the taxable year of the ownership change following the effective date) to which such a carryover is made (subject to various exceptions and adjustments) will be limited, resulting in an estimated $30.0 million of NOL's which are expected to expire due to the IRC section 382 limitation. Due to the factors discussed above, our net income for 2001 was $4.8 million, as compared to a net loss of $32.7 million for 2000. The loss for 2000 includes a writedown of our Tunisian oil and gas properties of $3.0 million. 2000 COMPARED WITH 1999 Operating Revenues. During 2000, production revenues increased 57% to $90.2 million as compared to $57.3 million in 1999. This increase was principally due to a 5% increase in crude oil production, a 51% increase in the price received for crude oil and a 67% increase in the price received for natural gas, including hedging losses discussed below, partially offset by a 20% decrease in natural gas production. During 1999, we experienced overall crude oil production declines in our operated properties due to capital constraints. During 2000, we experienced a 5% increase in daily crude oil production as compared to 1999 due to returning wells to production which were previously not producing due to depressed crude oil prices making it uneconomical to produce or repair such wells and due to increasing drilling activity on our operated properties. 41 The 20% decrease in natural gas production was primarily due to the natural declines on our operated and non-operated gas properties. The effect of natural production declines was partially offset by temporary increases in production due to several recompletions on our operated and nonoperated gas properties that were followed by rapid declines. Average crude oil prices increased 51% during 2000 compared to the same period in 1999, primarily due to strong demand for crude oil during 2000. During the first quarter of 1999, substantially all of our crude oil was sold under contracts which were based on posted crude oil prices. Subsequent to March 1999, substantially all of our Oklahoma crude oil has been sold under contracts which are based on the NYMEX price. Our overall average crude oil price per Bbl during 2000 was $23.31, including hedging losses of $2.79 per Bbl as discussed below, which represented a discount of 23% to the average NYMEX price in 2000. Our realized price for our natural gas increased 67% from $2.24 per Mcf in 1999 to $3.73 per Mcf in 2000, including hedging losses of $0.26 per Mcf as discussed below, due to an increase in demand for natural gas during 2000. Production revenues for 2000 included crude oil hedging losses of $9,856,000 ($2.79 per BOE) and natural gas hedging losses of $544,000 ($0.26 per Mcf). Production revenues for 1999 did not include any crude oil or natural gas hedging gains or losses. Expenses. Production expenses were $23.5 million for 2000 compared to $18.2 million for 1999. The increase in expenses from 1999 to 2000 is due primarily to: o increased electrical costs of approximately $1.8 million due to greater fluid movement and higher electrical rates; o increased chemical costs of approximately $609,000 due to increases in production; and o increased well repair costs of approximately $2.2 million due to more extensive repair work and costs to return shut in wells, inactive wells and marginal wells to production and increased costs between years for labor, materials and rigs related to well repair costs of approximately 10%, 5% and 20%, respectively. On a BOE basis, production costs increased 26% to $6.06 per BOE in 2000 compared to $4.82 per BOE in 1999. On a BOE basis, production costs increased because the increase in production did not keep pace with the increases in costs discussed above. Additionally, our well repair costs were higher in 2000 because we changed our approach to well repairs. In the past, our approach was generally to only repair any immediate problems with a well. We now evaluate the total condition of the well and repair any immediate problems as well as replace worn parts that may cause additional problems within the next year. Although the upfront repair costs are higher, future repair costs should decrease because the rig cost, which is generally a major cost in well repair work, is only incurred once and downtime for well repairs should decrease. Production taxes increased $2.8 million or 97% to $5.8 million during 2000 as compared to $2.9 million during 1999. This increase is due to increased crude oil production and due to higher realized prices. On a BOE basis, production taxes increased 91% to $1.49 per BOE during 2000 as compared to $.78 per BOE during 1999 due to higher realized prices. General and administrative costs decreased $2.8 million or 28% between the comparable periods. This decrease is primarily due to: o reductions of $2.4 million in employee-related costs, primarily due to the termination of officers and employees in April 2000 in conjunction with our plan of reorganization; o increases in cost recoveries from working interest owners due to an increase in well activity; and o capitalization of $765,000 of salaries and salary related costs associated with exploration and development activities. 42 These decreases were partially offset by increases in professional fees, primarily due to Hicks Muse litigation costs. State income tax penalties of $1.0 million for 1999 resulted from approximately $4 million in Louisiana state income taxes which were due on April 15, 1999, resulting from the gain on the December 1998 sale of the Monroe gas field. The past due taxes include the accrual of the maximum penalty of 25% of the taxes due. Interest expense increased 6% to $36.2 million in 2000 as compared to $33.9 million in 1999. The following is a summary of interest expense between comparable periods:

The increase for the comparable periods relates to several factors including the following: o an effective interest rate of 18.04% on the original $72 million standby loan issued March 31, 2000; o an effective rate of 23.92% on the paid-in-kind interest standby loan issued September 29, 2000; and o higher debt issuance amortization expense resulting from $33.8 million in debt issuance costs on our new debt, including $24.2 million related to the issuance of common stock in connection with the standby loan. These increases were partially offset by: o lower interest expense due to a reduction in our debt on March 31, 2000 resulting from the reorganization, o discontinuance of the accrual of interest on our old unsecured bonds as a result of our bankruptcy filing (approximately $3.5 million of additional interest expense would have been recognized during the first quarter of 2000 compared to $5.5 million for 1999, if not for the discontinuance of such interest expense accrual); and o higher interest rates and interest on past due interest on our old bank loan for a shorter period in 2000 as compared to 1999. The average interest rate on outstanding indebtedness was 12.48% in 2000, excluding interest expense related to the embedded derivative, compared to 8.55% in 1999. Loss on standby loan embedded derivative for the year ended 2000 of $15.2 million relates to the change in estimated future additional interest payments calculated on the standby loan. The aggregate amount of the additional interest payments were estimated at March 31, 2000 for the original $72 million standby loan and at September 29, 2000 for the $5.4 million paid-in-kind interest standby loan using the future crude oil and natural gas price curves as of such dates. The aggregate amount of additional interest payments was redetermined at December 31, 2000 using the then current crude oil and natural gas curves. The increase of $15.2 million in the aggregate amount of additional interest payments based on the December 31, 2000 price curves as compared to the aggregate amount of additional interest payments based on the March 31, 2000 and September 29, 2000 price curves was charged to loss on standby loan embedded derivative during 2000. Depletion and depreciation expense increased 11% to $15.2 million in 2000 from $13.7 million in 1999. This increase is primarily the result of increased production volumes and an increased depletion and depreciation rate per BOE, 43 which was $3.94 in 2000, compared with $3.63 in 1999. The depletion and depreciation rate per BOE increased due to an increase in depletable costs and due to a decline in total proved reserves. During 2000, we reclassified unproved property costs totaling $25.7 million that had been excluded from depletable costs as of December 31, 1999 to costs subject to depletion at December 31, 2000. These costs were reclassified because certain of the unproved projects were not viewed as economically attractive by our new management team and will not be performed in the foreseeable future. See "Item 2. Business and Properties - Oil and Gas Operations-Reserves" for a discussion of the decline in total proved reserves. During 2000, we decided to discontinue our participation in the exploration of two Tunisia, North Africa permits. In February 2001, the two subsidiaries that own these permits filed for protection under Chapter 11 of the United States Bankruptcy Code to preserve our ownership in these permits under the protection of the bankruptcy court while we try to negotiate sales of our interests in the permits to a third party or parties and to reach settlements with respect to our obligations under the permits. As a result, we took a writedown of $3.0 million, representing our remaining carrying costs on these permits, during the fourth quarter of 2000. Reorganization costs increased $8.9 million to $12.0 million in 2000 as compared to $3.1 million in 1999. This increase relates to: o professional fees for consultants and attorneys assisting in the negotiations associated with reorganization alternatives and approval and implementation of our plan of reorganization; o termination benefits for severed employees; o payments and accrual of settlement amounts for officer employment agreements and officer severance agreements which were rejected in the plan of reorganization; o payments and accrual of amounts made under our retention bonus plan; and o provisions for settlements of disputed bankruptcy claims and other costs to effect the plan of reorganization. Due to the factors discussed above, our net loss for 2000 was $32.7 million, as compared to a net loss of $30.7 million for 1999. The losses include writedowns of our Tunisian oil and gas properties of $3.0 million and $5.4 million for 2000 and 1999, respectively. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We use financial instruments which inherently have some degree of market risk. The primary sources of market risk include fluctuations in commodity prices and interest rate fluctuations. PRICE FLUCTUATIONS Effect of Price Fluctuations - Hedging Contracts. Our results of operations are highly dependent upon the prices received for crude oil and natural gas production. We have entered, and expect to continue to enter, into forward sale agreements or other arrangements for a portion of our crude oil and natural gas production to hedge our exposure to price fluctuations. Currently, all of our hedge arrangements are with the JPMorgan Chase Bank. At December 31, 2001, we have hedged a portion of our crude oil production through December 31, 2002. To calculate the potential effect of the hedging contracts on our operating income, we applied prices from December 31, 2001 future crude oil price curves for 2002 to the quantity of our oil production hedged for this period. In addition, we applied December 31, 2001 future crude oil pricing from the price curves assuming a 10% increase in prices and assuming a 10% decrease in prices. The estimated increases in operating income through December 31, 2002 resulting from the hedging contracts are as follows:

44 Effect of Price Fluctuations - Additional Interest. At December 31, 2001, a principal amount of $93.5 million was outstanding under our senior subordinated notes due 2007, which we also refer to as our standby loan agreement. The standby loan bears interest at a minimum rate of 15% payable semiannually plus additional interest, after March 31, 2001, in an amount equal to 1/2% for every $0.25 that the actual price, net of hedging costs, for our oil and gas production exceeds $15.00 per barrel of oil equivalent during the applicable semiannual interest period, up to a maximum of 10% additional interest per year. At December 31, 2001, using then current future crude oil and natural gas curves, we calculated the estimated future additional interest payments due through December 31, 2002 based on the principal amount of $93.5 million outstanding at December 31, 2001. In addition, we calculated the estimated additional interest payments due through December 31, 2002 assuming a 10% decrease in prices and a 10% increase in prices. The estimated additional interest due through December 31, 2002 relating to the additional interest under the standby loan is as follows: Based on current price curve $3,027,000 Based on 10% decrease in price curve $2,570,000 Based on 10% increase in price curve $4,205,000

Interest payments under the standby loan agreement are required to be paid-in-kind subject to the intercreditor arrangement between the standby lenders and the lenders under the senior revolving credit facility unless we meet specified tests. "Paid-in-kind" refers to the payment of interest owed under the standby loan by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for discussion on interest payments to be paid-in-kind. INTEREST RATE RISK Total debt as of December 31, 2001, included $195 million of floating-rate debt attributed to bank credit facility borrowing. As a result, our annual interest cost in 2002 will fluctuate based on short-term interest rates. The impact on annual cash flow of a ten percent change in the floating interest rate (approximately 50 basis points) would be approximately $975,000 assuming outstanding debt of $195 million throughout the year. We have locked in a rate of 5% (2% LIBOR plus 3% margin) thru May 13, 2002 on $175 million of bank credit facility borrowings. 45 ITEM 8. FINANCIAL STATEMENTS Report of Independent Public Accountants........................................................ 47 Consolidated Balance Sheets, December 31, 2000 and 2001......................................... 48 Consolidated Statements of Operations, Years Ended December 31, 1999, 2000 and 2001............. 49 Consolidated Statements of Shareholders' Equity, Years Ended December 31, 1999, 2000 and 2001... 50 Consolidated Statements of Cash Flows, Years Ended December 31, 1999, 2000 and 2001............. 51 Notes to Consolidated Financial Statements, Years Ended December 31, 1999, 2000 and 2001........ 52

46 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Shareholders of Coho Energy, Inc. We have audited the accompanying consolidated balance sheets of Coho Energy, Inc. and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Coho Energy, Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States. As explained in Note 1 to the financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging transactions. The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements, the Company has suffered recurring losses and has received a notice of default from its lenders under its existing bank credit facility and is in default under the terms of its standby loan agreement that raise substantial doubt about the Company's ability to continue as a going concern. On February 6, 2002 the Company, together with certain of its wholly owned subsidiaries, filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code and is currently operating as a debtor-in-possession subject to the bankruptcy court's supervision and orders. The financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern. Arthur Andersen LLP Dallas, Texas March 29, 2002 47 COHO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS) ASSETS

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 48 COHO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 49 COHO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS, EXCEPT SHARE AMOUNTS)

(a) Comprehensive income for the years ended December 31, 1999, 2000 and 2001 was $(30,715), $(32,722) and $6,810, respectively. SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 50 COHO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)

SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 51 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization Coho Energy, Inc. ("CEI") was incorporated in June 1993 as a Texas corporation and conducts a majority of its operations through its subsidiary, Coho Resources, Inc. ("CRI"), and its subsidiaries (collectively the "Company"). Principles of Presentation These consolidated financial statements have been prepared in conformity with generally accepted accounting principles as presently established in the United States and include the accounts of CEI as successor to CRI, and its subsidiaries. All significant intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the prior year statements to conform with the current year presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Substantially all of the Company's exploration, development and production activities are conducted in the United States jointly with others and, accordingly, the financial statements reflect only the Company's proportionate interest in such activities. Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include cash and highly liquid debt instruments purchased with an original maturity of three months or less. Cash in Escrow Substantially all of the cash at December 31, 2000 was held in escrow pursuant to a drilling contract between the Company and a drilling contractor. Such funds were disbursed to the drilling contractor upon completion of services. Accounts Receivable The Company performs ongoing reviews with respect to the collectibility of accounts receivable and maintains an allowance for doubtful accounts receivable ($675,000 and $488,000 at December 31, 2000 and 2001, respectively) based on expected collectibility. Crude Oil and Natural Gas Properties The Company's crude oil and natural gas producing activities, substantially all of which are in the United States, are accounted for using the full cost method of accounting. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition of crude oil and natural gas properties and with the exploration for and development of crude oil and natural gas reserves, including related gathering facilities. Proceeds from disposition of crude oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss recognized unless such dispositions involve a significant alteration in the depletion rate in which case the gain or loss is recognized. 52 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Depletion of crude oil and natural gas properties is provided using the equivalent unit-of-production method based upon estimates of proved crude oil and natural gas reserves and production which are converted to a common unit of measure based upon their relative energy content. Unproved crude oil and natural gas properties are not amortized, but are individually assessed for impairment. The costs of any impaired properties are transferred to the balance of crude oil and natural gas properties being depleted. Estimated future site restoration and abandonment costs are charged to earnings at the rate of depletion of proved crude oil and natural gas reserves and are included in accumulated depletion and depreciation. In accordance with the full cost method of accounting, the net capitalized costs of crude oil and natural gas properties as well as estimated future development, site restoration and abandonment costs are not to exceed their related estimated future net revenues discounted at 10%, net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. Impairment of Long-Lived Assets During 1996, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived-Assets To Be Disposed Of." The Company has no long-lived assets which are subject to the impairment test requirements of SFAS No. 121. The Company's only long-lived assets are oil and gas properties which are subject to the full cost ceiling test in accordance with the full cost method of accounting, as discussed above. Other Assets Other assets generally include deferred financing charges which are amortized over the term of the related financing under the straight-line method. At December 31, 2001, the Company had unamortized deferred financing charges associated with the credit facility and standby loan agreement of $2.9 million and $20.3 million, respectively. Asset Retirement Obligations In June 2001, SFAS No. 143, "Accounting for Asset Retirement Obligation" was issued. This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, a corresponding increase in the carrying amount of the related long-lived asset would be recorded. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss on settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently evaluating the effect on its financial statements of adopting SFAS No. 143 and plans to adopt the statement effective January 1, 2003. Stock-Based Compensation SFAS No. 123, "Accounting for Stock-Based Compensation," encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to continue to apply Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations to account for stock-based compensation. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at earliest of the date of the grant or the first date the exercise price can be determined over the exercise price an employee must pay to acquire the stock. Earnings Per Common Share The Company accounts for earnings per share ("EPS") in accordance with SFAS No. 128, "Earnings Per Share." Under SFAS No. 128, no dilution for any potentially dilutive securities is included for basic EPS. EPS have been calculated based on the weighted average number of shares outstanding and diluted EPS have been calculated based on the weighted average number of shares outstanding (including common shares plus, when their 53 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) effect is dilutive, common stock equivalents consisting of stock options and warrants). Basic and diluted EPS have been calculated on the weighted average number of shares for the years ended 1999, 2000 and 2001 of 640,088, 14,266,336 and 18,714,175, respectively. In 1999 and 2000, conversion of stock options and warrants would have been antidilutive and, therefore, was not considered in diluted EPS. On March 31, 2000, pursuant to the plan of reorganization, old shareholders of the Company's common stock received one share of the Company's new common stock for each forty shares of the Company's old common stock. All per-share amounts have been restated based on the new number of shares outstanding subsequent to the issuance of new shares. Income Taxes The Company accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Hedging Activities and Other Derivative Instruments The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" effective January 1, 2001. The Statement required the Company to recognize all derivative instruments (including certain derivative instruments embedded in other contracts) on the balance sheet as either an asset or liability based on fair value on January 1, 2001. The accumulated effect of this accounting change resulted in an increase in net income of $9.2 million and a decrease in other comprehensive income ("OCI") of $5.8 million during 2001. Subsequent changes in fair value for the effective portion of derivatives qualifying as hedges are recognized in OCI until the sale of the related hedged production is recognized in earnings, at which time changes in fair value previously recognized in other comprehensive income are reclassified to earnings and recognized in operating revenues. Based on the OCI recorded as of December 31, 2001, $2.0 million of deferred net gains on derivatives would be reclassified to earnings during the next twelve-month period upon the sale of hedged production. Subsequent changes in fair value for the ineffective portion of derivatives qualifying as hedges and for derivatives that are not hedges must be adjusted to fair value through earnings and recognized in loss on derivatives in the period where the change in fair value occurs. During 2001, the Company recorded losses on derivatives due to changes in the fair value for the ineffective portion of derivatives of $494,000. Certain derivatives, representing 3% of our hedging arrangements at December 31, 2001, which previously qualified for hedge accounting treatment under SFAS No. 133 failed to qualify for such treatment during the third quarter of 2001, resulting in a reduction in loss on derivatives of $266,000 during 2001. The Company has entered into certain arrangements that fix a minimum and maximum price range for a portion of its future crude oil and natural gas production. The Company entered into these arrangements to reduce the downside risk associated with potential crude oil and natural gas price declines by setting a floor price for its future production based on the NYMEX crude oil and natural gas prices. Due to working capital constraints, the Company entered into the "costless collar" type of transactions because they do not require upfront premiums. A significant portion of these hedge arrangements qualify as cash flow hedges under SFAS No. 133. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for further discussion on the Company's hedge arrangements and a summary of the Company's existing hedge arrangements. The Company has entered into notes in connection with the standby loan agreement and certain lease agreements which contain provisions for payments based on crude oil and natural gas prices. These agreements are considered to include embedded derivatives under SFAS No. 133. See note 5 for additional discussion on agreements containing embedded derivatives. Revenue Recognition Policy Revenues generally are recorded when products have been delivered and services have been performed. 54 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Environmental Expenditures Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures which improve the condition of a property as compared to the condition when originally constructed or acquired or prevent environmental contamination are capitalized. Expenditures which relate to an existing condition caused by past operations, and do not contribute to future operations, are expensed. The Company accrues remediation costs when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated. Business Segments In June 1997, the Financial Accounting Standards Board issued SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information", which requires information to be reported in segments. The Company currently operates in a single reportable segment; therefore, no additional disclosure is required. 2. REORGANIZATION UNDER BANKRUPTCY PROCEEDINGS DURING 2000 On August 23, 1999 (the "Petition Date"), the Company and its wholly-owned subsidiaries, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production Company and Interstate Natural Gas Company, filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code (the "Chapter 11 filing") in the U.S. District Court for the Northern District of Texas (the "Bankruptcy Court"). On November 30, 1999, the Company filed a plan of reorganization and subsequently filed an amended plan of reorganization on February 14, 2000 (the "Plan of Reorganization"). On March 20, 2000, the Bankruptcy Court entered an order confirming the Plan of Reorganization and on March 31, 2000, the Plan of Reorganization was consummated and the Company emerged from bankruptcy. Prior to March 31, 2000, the effective date of the Plan of Reorganization, the Company had 25,603,512 shares of old common stock issued and outstanding. Old shareholders received shares representing 4% of new common stock on a basis of one share of new common stock for 40 shares of old common stock as of the effective date without giving effect to dilution from shares issued in connection with the standby loan or shares issued under the rights offering discussed below. Additionally, shareholders as of February 7, 2000, are eligible to receive their pro rata share of 20% of any proceeds available from the lawsuit filed against five affiliates of Hicks, Muse, Tate & Furst (the "Hicks Muse Lawsuit") after fees and expenses and 40% of any proceeds of the disposition of the Company's interest in, or the assets of, Coho Anaguid, Inc. Coho Anaguid owned a 45.83% interest in a permit in Tunisia, North Africa. At March 31, 2000, the Company charged 40% of the carrying value of Coho Anaguid, Inc., approximately $1.1 million, to reorganization expense. On May 2, 2000, the Company distributed stock rights to the holders of its old common stock as of the record date of March 6, 2000, to purchase up to an aggregate of 8,663,846 shares of its new common stock. There were 14,669 rights exercised under the offering; however, pursuant to an antidilution feature which applied to shares issued in the rights offering, 1.17 shares were issued for each right exercised. Unexercised rights expired May 31, 2000. The Company received $153,000 upon completion of the offering on May 31, 2000. Proceeds from the rights offering were used to pay offering costs; however, offering costs exceeded the proceeds from the rights offering and the excess costs were charged to accrued reorganization costs. The reorganized value of the Company's assets exceeded the total of all postpetition liabilities and allowed claims; therefore, the Company did not qualify for fresh-start accounting. The Company has recorded the following transactions to effect the Company's Plan of Reorganization consummated on March 31, 2000: o The borrowing of $183.0 million under a new credit facility. o The borrowing of $72.0 million under the standby loan and the issuance of 2,694,841 shares of new common stock as debt issuance costs at a diluted reorganization value of approximately $9.00 per share for a total of $24.2 million. The diluted reorganization value of $9.00 per share was caused by the old bondholders accepting a dilution in the value of their new common stock to obtain the standby loan 55 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) financing for the reorganized company. The dilution is a result of the issuances of additional shares to the standby lenders. o Repayment of borrowings outstanding under the old bank credit facility together with accrued interest and reasonable fees totaling $260.2 million, resulting in a $303,000 loss on extinguishment of debt. o Conversion of the old bonds into 15,362,107 shares of new common stock, representing 96% of the new common stock without giving effect to dilution from shares issued in connection with the standby loan or shares issued under the rights offering, at a reorganization value of approximately $10.52 per share resulting in a $4.1 million loss on extinguishment of debt. Although the old bonds were paid no more than in full, the Company did realize a loss on extinguishment of debt because the Company's carrying value of the old bonds was less than the allowed claim, primarily due to unamortized debt issuance costs. o Provision of $1.6 million to allow for settlement of disputed claims. o Payment of all allowed senior secured claims and all other allowed claims less than $1,000, aggregating approximately $500,000. All other allowed claims will be or have been paid in full as follows: o Substantially all unsecured claims were paid in full in four quarterly installments with the final installment made on January 2, 2001. o Priority tax claims received five-year, interest-bearing promissory notes. o Payment of costs associated with the bankruptcy were paid upon court approval during the six months following the consummation of the Plan of Reorganization. In conjunction with its Plan of Reorganization, the Company terminated 19 corporate office employees and seven officers in April 2000. Costs of $438,000 associated with termination benefits for the 19 corporate office employees were accrued as of March 31, 2000 and charged to reorganization expense and subsequently paid in the quarter ended June 30, 2000. Additionally, the Company rejected all of its officer employment agreements and officer severance agreements in connection with the Plan of Reorganization, including the seven terminated officers. The Company negotiated settlement agreements related to the claims for these rejected contracts. Approximately $3.0 million was accrued and charged to reorganization expense for these claims settlements which were paid during the nine months following the consummation of the Plan of Reorganization. The Company's Plan of Reorganization provided for a retention plan under which employees were provided with additional incentives to continue their employment with the Company throughout 2000. The amount of cash awards paid under the retention plan was $1.2 million, of which 33% was paid upon the effective date of the Plan of Reorganization and 67% was paid on January 1, 2001. 3. BANKRUPTCY PROCEEDINGS - SUBSEQUENT EVENTS On November 1, 2001, the lenders under the senior revolving credit facility notified the Company that its borrowing base under this facility had been redetermined in the semi-annual review from $195 million to $175 million effective November 1, 2001 causing a borrowing base deficiency of $20 million as discussed more fully under Note 5. The Company did not have sufficient working capital to cure the borrowing base deficiency within the 90 day cure period and on February 1, 2002 a notice of default was issued by the lenders under the senior revolving credit facility. The Company is also in default under the terms of its standby loan agreement. On February 6, 2002, the Company and its wholly owned subsidiaries, Coho Resources, Inc. and Coho Oil & Gas, Inc., filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Northern District of Texas. The bankruptcy petitions were filed to protect the Company while it develops a solution to its liquidity problems. The Company is currently operating as debtor-in-possession under the court's supervision and pursuant to its orders. The Company filed schedules with the bankruptcy court on March 8, 2002. Those schedules contain the Company's unaudited, and in some cases, estimated assets and liabilities as of February 6, 2002, as shown by the Company's accounting records. 56 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Under the cash collateral order, the Company has agreed with the lenders under the senior credit facility to develop a marketing plan with the Company's new financial advisor, CIBC, for the sale of its assets or a recapitalization of its debt and equity. The Company, together with CIBC, is currently working with the bank group and the unsecured creditors committee on mutually acceptable terms for this marketing plan to achieve maximum value for the Company's assets in this process. The marketing plan will allow the Company to explore other alternatives available, in addition to a sale of the Company's assets, including a recapitalization of the Company's debt and equity from existing or new investors to cure the $20 million borrowing base deficiency and to provide working capital to develop its properties. A recapitalization may include a partial sale of assets. Any sale or recapitalization will be subject to bankruptcy court approval under a Chapter 11 plan of reorganization or liquidation or in accordance with Section 363 of the bankruptcy code, which generally provides for a partial sale of assets prior to confirmation of a plan of reorganization or liquidation. No adjustments to the carrying value of the Company's assets or liabilities related to the bankruptcy filing have been reflected in the December 31, 2001 balance sheet. In accordance with SOP 90-07, "Financial Reporting by Entities in Reorganization under the Bankruptcy Code", during 2002, the Company will adjust liabilities subject to compromise to its estimate of the allowed claims. Accordingly, during 2002, the Company will write-off unamortized debt issuance costs and debt discounts of $22.6 million and $10.7 million, respectively. These adjustments to the December 31, 2001, carrying values will be recorded in earnings as reorganization items. In addition, the Company will record the prepayment penalty ($30.8 million at December 31, 2001) and adjust the recorded amount of the standby loan embedded derivative, based on the estimated allowed claims in the first quarter of 2002. At this time, it is not possible to predict the outcome of the bankruptcy proceedings, in general, or the effect on the Company's business or on the interests of the creditors or shareholders. Management believes, however, that is may not be possible to satisfy in full all of the claims against the Company. In addition, the shareholders of the Company may not realize any value on their investment. As a result of the bankruptcy filing, all of the Company's liabilities incurred prior to February 6, 2002, including secured debt, are subject to compromise. Under the bankruptcy code, payment of these liabilities may not be made except pursuant to a plan of reorganization or liquidation or bankruptcy court approval. The financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts (including $333 million in net property, plant and equipment) or the amount and classification of liabilities that might result should we be unable to continue as a going concern. Our ability to continue as a going concern is dependent upon the confirmation of a plan of reorganization, adequate sources of capital and the ability to sustain positive results of operations and cash flows sufficient to continue to explore for and develop proved oil and gas reserves. These factors, among others, raise substantial doubt concerning our ability to continue as a going concern. Subsequent to February 6, 2001, the Company filed two motions with the bankruptcy court to seek use of the bank group's cash collateral on an on-going basis. Since filing bankruptcy, the Company has been operating under two orders authorizing the use of cash collateral, initially an interim order and currently a final order which was approved on February 26, 2002 and authorizes expenditures through April 30, 2002. Under these orders, the Company may pay for ordinary course of business goods and services incurred after February 6, 2002 that are within the court approved budgets attached to each order. Any expenditure that is outside the ordinary course of business or that is not reflected in the approved budgets must be specifically approved by the bankruptcy court. 4. PROPERTY AND EQUIPMENT

Overhead expenditures directly associated with exploration for and development of crude oil and natural gas reserves have been capitalized in accordance with the accounting policies of the Company. Such charges totaled $0, $765,000 and $960,000 in 1999, 2000 and 2001, respectively. During 1999 and the first quarter of 2000, all overhead expenditures were charged to general and administrative expense due to the cessation of exploration and 57 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) development of crude oil and natural gas reserves during such period. Subsequent to the first quarter of 2000, the Company increased development work, therefore related overhead and expenditures were capitalized for the remainder of the year 2000 and 2001. During 1999, 2000 and 2001, the Company did not capitalize any interest or other financing charges on funds borrowed to finance unproved properties or major development projects. Unproved crude oil and natural gas properties totaling $30,603,000 and $0 at December 31, 2000 and 2001, respectively, have been excluded from costs subject to depletion. Depletion and depreciation expense per equivalent barrel of production was $3.63, $3.94 and $4.50 in 1999, 2000 and 2001, respectively. During the fourth quarter of 2001, the Company reclassified unproved property costs totaling $30.6 million that had been excluded from depletable costs as of December 31, 2000 to costs subject to depletion at December 31, 2001. These costs were reclassified because most unproved projects will not be performed in the foreseeable future due to capital constraints and additionally, certain of the unproved projects are no longer viewed as economically attractive by the Company's management team. 5. LONG-TERM DEBT

The Company and some of its subsidiaries were parties to an old bank group loan agreement. Borrowings outstanding under the old bank group loan together with accrued interest and fees totaling $260.2 million were paid on March 31, 2000. The Company obtained the funds necessary for the payment of the old bank group loan through the combination of borrowings under its new senior revolving credit facility, borrowings under the standby loan and from cash accumulated during the bankruptcy. Additionally, the Company owed approximately $162 million of principal and accrued interest under its old bonds. Under the Plan of Reorganization, these old bonds and accrued interest were converted into 15,362,107 shares of new common stock. Credit Facility The existing senior revolving credit facility was obtained from a syndicate of lenders led by JP Morgan, as agent for the lenders, and has a maximum loan commitment amount of $250 million. The credit facility limits permitted advances to the amount of the borrowing base, which is subject to semiannual borrowing base redeterminations each April 1 and October 1, based on the Company's reserve reports, and will be made at the sole discretion of the lenders. The April 1, 2001 redetermination resulted in a decrease in the Company's borrowing base from $205 million to $195 million. At December 31, 2001, $195 million in advances were outstanding under the revolving credit facility. On November 1, 2001, the lenders under the senior revolving credit facility notified the Company that its borrowing base under this facility had been redetermined in the semiannual review from $195 million to $175 million effective November 1, 2001. On November 2, 2001, the Company received a notice of borrowing base deficiency because borrowings under this facility exceed the redetermined borrowing base by $20 million. Under 58 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) the credit facility, the Company could have remedied the borrowing base deficiency by providing additional collateral sufficient to eliminate the borrowing base deficiency or made a cash payment sufficient to eliminate the borrowing base deficiency on or before January 31, 2002. Currently, all of the Company's assets are pledged as collateral under the credit facility and the Company did not have sufficient working capital to make a cash payment that would eliminate the borrowing base deficiency within the 90 day cure period. On February 1, 2002, the Company received a notice of default under the credit facility and subsequently filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. See Note 3 for further discussion on bankruptcy proceedings. At December 31, 2001, the outstanding advances of $195 million under the senior revolving credit facility were classified as a current liability due to the default under the credit facility. Interest on advances under the credit facility is payable on the earlier of the expiration of any interest period under the credit facility or quarterly. Amounts outstanding under the credit facility accrue interest at the Company's option at either the Eurodollar rate, which is the annual interest rate equal to the London Interbank Offered Rate for deposits in United States dollars that is determined by reference to the Telerate Service or offered to Chase plus an applicable margin (currently 3%), or the prime rate, which is the floating annual interest rate established by Chase from time to time as its prime rate of interest plus an applicable margin (currently 2%). In the event any principal is not paid when due, whether at maturity or upon acceleration, interest will accrue at the applicable rate, as discussed above, plus 2%. All outstanding advances are due and payable on March 31, 2003 pursuant to the original terms of the credit facility. The credit agreement contains financial and other covenants including: o maintenance of required ratios of cash flow to interest expense paid or payable in cash (not less than 2.75 to 1 for the average of the last four consecutive quarters most recently ended December 31, 2001; and 3.0 to 1 for the average of the last four quarters for any quarter ending after January 1, 2002), senior debt to cash flow required (not to exceed 3.75 to 1 for the average of the last four quarters most recently ended December 31, 2001; and 3.5 to 1 for the average of the last four consecutive quarters for any quarter ending after January 1, 2002), and current assets (including unused borrowing base) to current liabilities required (throughout the term of the credit agreement, to be not less than 1 to 1 as of the end of each quarter); o restrictions on the payment of dividends; and o limitations on the incurrence of additional indebtedness, the creation of liens and the incurrence of capital expenditures. The Company was unable to maintain the required ratio of senior debt to cash flow and current assets to current liabilities, as required by the credit agreement during the fourth quarter of 2001. The Company believes that it was in compliance with all other covenants under the credit facility at the end of the fourth quarter of 2001. As of December 31, 2001, the covenant ratios of cash flow to interest expense, senior debt to cash flow, and current assets to current liabilities were 2.79 to 1, 4.7 to 1, and .06 to 1, respectively. Non-cash transactions resulting from the adoption and accounting treatment of SFAS No. 133 are excluded from the calculation of covenant ratios under the credit facility. Standby Loan The standby loan was made under a senior subordinated note facility under which the Company issued $72 million of senior subordinated notes, herein referred to as the "standby loan", to PPM America, Inc., Appaloosa Management, L.P., Oaktree Capital Management, L.L.C., Pacholder Associates, Inc. and their respective assignees. At December 31, 2001, an aggregate of $93.5 million of senior subordinated notes was outstanding under the standby loan. The Company's rights and responsibilities and those of the standby lenders are governed by a standby loan agreement dated March 31, 2000. Debt under the standby loan agreement is evidenced by notes maturing March 31, 2007 and bearing interest at a minimum annual rate of 15% and payable in cash semiannually. After March 31, 2001, additional semiannual interest payments are payable in an amount equal to 1/2% for every $0.25 that the "actual price" (as described below) for the Company's oil and gas production exceeds $15 per barrel of oil equivalent during the applicable 59 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) semiannual interest period, up to a maximum of 10% additional interest per year. Any time the average realized price exceeds $20 per barrel of oil equivalent, the Company will have to pay the 10% maximum additional interest. The "actual price" for the Company's oil and gas production is the weighted average price received by the Company for all its oil and gas production, including hedged and unhedged production, net of hedging costs, in dollars per barrel of oil equivalent using a 6:1 conversion ratio for natural gas. The actual price will be calculated over a six-month measurement period ending on the date two months before the applicable interest payment date. Additionally, upon an event of default occurring under the standby loan, interest will be payable in cash, unless otherwise required to be paid-in-kind, at a rate equal to 2% per year over the applicable interest rate. The senior subordinated notes require semiannual interest payments which are required to be paid-in-kind under the intercreditor arrangement between the standby lenders and the lenders under the senior revolving credit facility unless we meet specified financial tests. "Paid-in-kind" refers to the payment of interest owed under the standby loan by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. The standby loan semiannual interest payments of $5.8 million were paid-in-kind when due on March 30, 2001 and were reflected at issuance as an increase in long term debt and long term derivative liabilities of $4.4 million and $1.4 million, respectively. The standby loan interest payments of $10.3 million, which were at the maximum interest rate of 25%, were paid-in-kind when due on September 28, 2001 and were reflected at issuance as an increase in long term debt and long term derivative liabilities of $8.3 million and $2.0 million, respectively. Previously, interest accruing on the standby loan, subsequent to the previous semiannual interest payment was reflected in long term debt until the next semiannual interest was paid in cash or paid-in-kind; however, due to the default under the standby loan agreement, as discussed below, accrued interest at December 31, 2001 was classified as a current liability. The Company adopted SFAS No. 133 effective January 1, 2001. This statement required the Company to record the fair value of the additional semiannual interest feature, which is considered an embedded derivative, in long term derivative liabilities (see Note 6). Accordingly, a debt discount has been recorded related to the standby loans reflecting the fair value of the embedded derivatives at the date the original notes were issued. The debt discount is amortized into interest expense using the straight line method over the term of the related notes. Prior to adoption of SFAS No. 133, which was effective January 1, 2001, the estimated future additional interest payments were calculated at each balance sheet date and the change in estimated future additional interest payments was recorded as long term debt. The aggregate amount of the additional interest payments were estimated at March 31, 2000 for the original $72 million standby loan and at September 29, 2000 for the $5.4 million paid-in-kind interest standby loan using the future crude oil and natural gas price curves as of such dates. The aggregate amount of additional interest payments was redetermined at December 31, 2000 using the then current crude oil and natural gas curves. The increase of $15.2 million in the aggregate amount of additional interest payments based on the December 31, 2000 price curves as compared to the aggregate amount of additional interest payments based on the March 31, 2000 and September 29, 2000 price curves was recorded as long term debt standby loan embedded derivative during 2000. Payment of the standby loan notes will be expressly subordinate to payments in full in cash of all obligations arising in connection with the credit facility. After the initial 12-month period, cash interest payments may be made only to the extent by which EBITDA, or earnings before interest, tax, depreciation and amortization expense, on a trailing four-quarter basis exceeds $65 million. The credit agreement also prohibits the Company from making any cash interest payments on the standby loan indebtedness if the outstanding indebtedness under both the new credit facility and the standby loan exceeds 3.75 times the EBITDA for the trailing four quarters. The Company does not currently meet the requirements to make cash interest payments on the standby loan indebtedness. The Company may prepay, or may be required to repay, under certain circumstances, the standby loan notes at the face amount, in whole or in part, in minimum denominations of $1,000,000, plus either a standard make-whole payment at 300 basis points over the "treasury rate" for the first four years, or beginning in the fifth year, a prepayment fee of 7.5% of the principal amount being prepaid; in the sixth year, a prepayment fee of 3.75% of the principal amount being prepaid; and after the sixth year there is no prepayment fee. The "treasury rate" is the yield of U.S. Treasury securities with a term equal to the then-remaining term of the standby loan notes that has become publicly available on the third business day before the date fixed for repayment. As of December 31, 2001, the prepayment fee for the then total outstanding principal amounts, using then current treasury rates, would have been approximately $30.8 million. 60 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The standby loan agreement contains certain covenants and cross default provisions, including cross default provisions which automatically cause the Company to be in default under the terms of the standby loan agreement in the event the Company is in default under the senior revolving credit facility or in the event the Company seeks relief under any provision of the bankruptcy law. In the event of default, the standby lenders may declare all amounts due under the standby loan agreement immediately due, unless the default is due to bankruptcy proceedings, which will automatically accelerate all amounts due, including principal, accrued interest and the prepayment fee. On February 1, 2002, the Company received a notice of default under the senior revolving credit facility. This default automatically caused the Company to be in default under the standby loan agreement. On February 6, 2002, the Company filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code which automatically accelerated all amounts due, including the prepayment fee, under the standby loan. Due to the default under the standby loan agreement, the carrying value of the Company's outstanding debt at December 31, 2001 was classified as a current liability. The prepayment fee has not been recorded on the Company's balance sheet as of December 31, 2001. When the standby loan notes were issued on March 31, 2000, the standby lenders became entitled to 14.4% of the Company's fully diluted new common stock valued at approximately $24.2 million. The shares were registered with the Securities and Exchange Commission in connection with the rights offering and were issued on June 1, 2000. The shares of new common stock issued to the standby lenders were in addition to the shares of new common stock issued to holders of the old bonds, to the Company's shareholders prior to reorganization and to persons participating in the rights offering. Additionally, the standby lenders received closing fees of approximately $2.5 million as well as expense reimbursements. Promissory Notes Claims for tax, penalty and interest were filed against the Company by the State of Louisiana and the State of Mississippi. The Company has settled claims with both taxing authorities. Five-year, interest-bearing promissory notes were issued for settlement of these priority tax claims, of which $2.7 million is included in long-term debt and $709,000 is included in current portion of long term debt. Other The Company has settled the claims of Chevron Corp. and Chevron USA for indemnification of any environmental liabilities in the Brookhaven field. The terms of this settlement require the Company to fund $2.5 million over a two-year period to partially finance the implementation of a remediation plan. The Company paid $1.0 million in June 2000, $500,000 on January 1, 2001 and $1.0 million on January 1, 2002. The $1.0 million payment paid in 2002 is included in current portion of long term debt. Debt Repayments Based on the balances outstanding under the new credit facility, the standby loan agreement (excluding unamortized debt discount of $10.9 million), the promissory notes, and the Chevron settlement, estimated aggregate principal repayments for each of the next five years are as follows: 2002 - $290,161,000, 2003 - $756,000, 2004 - $805,000, 2005 - $858,000, 2006 - $291,000, and $0 thereafter. 6. DERIVATIVE LIABILITIES The standby loan agreement (see Note 5) contains an additional semiannual interest feature which is calculated based on the actual price the Company receives for its oil and gas production. The additional interest feature of the standby loan agreement is considered an embedded derivative under SFAS No. 133. The fair value of the embedded derivative is recorded on the balance sheet and included in current liabilities as accrued unrealized loss on derivatives in the amount of $11.8 million at December 31, 2001. The embedded derivative is classified as a current liability due to the default under the standby loan agreement as described in Note 5. Certain leases in Laurel, Mississippi contain provisions for a portion of the lease payments to be based on the price of crude oil. These provisions are considered embedded derivatives under SFAS No. 133 and are recorded at 61 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) their fair value of $285,000, with $28,000 recorded in current liabilities and $257,000 in long term derivative liabilities, at December 31, 2001. 7. COMPREHENSIVE INCOME Comprehensive income includes net income and certain items recorded directly to Stockholders' Equity and classified as OCI. Following the adoption of SFAS No. 133 on January 1, 2001, the Company recorded a decrease of $5.8 million in OCI and has subsequently recorded additional changes in OCI related to the Company's crude oil and natural gas hedging arrangements. Comprehensive income for the years ended December 31, 2000 and December 31, 2001 is as follows:

8. SUPPLEMENTAL CASH FLOW INFORMATION During 1999 and 2001, all noncash transactions were disclosed on the Consolidated Statements of Cash Flows. Supplemental noncash financing activities for the year ended December 31, 2000 are as follows: New borrowing: Accounts receivable ............................................. $ (499) Debt issuance costs ............................................. 24,245 Changes in accounts payable and accrued liabilities ............. 5,847 Long-term debt .................................................. (5,245) Additional paid-in capital ...................................... (24,245) Reorganization expense .......................................... (103) --------- $ 0 --------- Extinguishment of debt: Debt issuance costs ............................................. $ (5,231) Accrued interest ................................................ 15,484 Current long-term debt .......................................... 149,081 Issuance of common stock ........................................ (161,636) Loss on extinguishment of debt .................................. 4,428 --------- Total cash paid ................................................... $ 2,126 --------- Embedded derivative and standby loan interest: Long-term debt .................................................. $ (25,253) Interest expense ................................................ 10,090 Interest expense related to embedded derivative ................. 15,163 --------- $ 0 =========

9. INCOME TAXES Deferred income taxes are recorded based upon differences between financial statement and income tax basis of assets and liabilities. The tax effects of these differences which give rise to deferred income tax assets and liabilities at December 31, 2000 and 2001, were as follows: 62 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)

The valuation allowance for deferred tax assets as of December 31, 2000 and 2001 includes $192,665 and $48,095, respectively, related to Canadian deferred tax assets. To determine the amount of net deferred tax liability it is assumed no future capital expenditures will be incurred other than the estimated expenditures to develop the Company's proved undeveloped reserves. The following table reconciles the differences between recorded income tax expense and the expected income tax expense obtained by applying the basic tax rate to earnings (loss) before income taxes:

63 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) At December 31, 2001, the Company had the following income tax carryforwards available to reduce future years' income for tax purposes:

10. SHAREHOLDERS' EQUITY To effect the Company's Plan of Reorganization in 2000, the Company: o issued new common stock to old shareholders on a basis of one share of new common stock for 40 shares of old common stock; o converted the old bonds into 15,362,107 shares of new common stock; o issued 2,694,841 shares of new common stock as debt issuance costs under the standby loan agreement; and o issued 17,139 shares of new common stock pursuant to a rights offering. See Note 2 for further discussion on the conversion of old common stock and the issuance of new common stock. 64 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) 11. STOCK-BASED COMPENSATION Prior to the consummation of the Plan of Reorganization in 2000, options to purchase the Company's common stock were granted to officers, directors and key employees pursuant to the Company's 1993 Stock Option Plan and 1993 Non Employee Director Stock Option Plan, or assumed from the reorganization of the Company's subsidiaries in 1993. The stock option plans provided for the issuance of five-year options with a three-year vesting period and a grant price equal to or above market value. Some exceptions were made to provide immediate or shortened vesting periods as approved by the Company's board of directors. All options outstanding or available for grant prior to the consummation of the Plan of Reorganization were terminated according to the Plan of Reorganization. Option shares and values for 1999 have not been restated to reflect the conversion of old common stock to new common stock (see Note 2). Subsequent to the consummation of the Plan of Reorganization, the Company granted options to purchase the Company's common stock to certain officers and directors of the Company. The options granted to the Company's officers vest over a two-year period and the options granted to the Company's directors are immediately vested on the grant date. A summary of the status of the Company's stock option plans at December 31, 1999, 2000 and 2001 and changes during the years then ended follows:

Significant option groups outstanding at December 31, 2001 and related weighted average price and life information follows:

(a) Options expire one year after termination of participant. 65 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The weighted average fair value of options at the date of grant for options granted during 2000 and 2001 was $4.42 and $2.93 per option, respectively. The fair value of options at date of grant was estimated using the Black-Scholes model with the following weighted average assumptions:

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:

(b) Per share amounts restated for conversion of old common stock to new common stock (see note 2) 12. COMMITMENTS AND CONTINGENCIES (a) Like other crude oil and natural gas producers, the Company's operations are subject to extensive and rapidly changing federal and state environmental regulations governing emissions into the atmosphere, waste water discharges and solid and hazardous waste management activities. At December 31, 2001, the Company has accrued approximately $500,000 related to such costs, of which $50,000 is included in current liabilities and $450,000 is included in contingent liabilities. At this time, the Company does not believe that any potential liability, in excess of amounts already provided for, would have a significant effect on the Company's financial position or the results of operations. (b) The Company's operations are subject to site restoration and abandonment costs. The Company's policy is to make a provision for future site restoration charges on a unit-of-production basis. Total future site restoration costs are estimated to be $6 million. A total of $3.3 million has been included in depletion and depreciation expense with respect to such costs as of December 31, 2001. (c) On May 27, 1999, the Company filed a lawsuit against five affiliates of Hicks, Muse, Tate & Furst. The lawsuit alleges (1) breach of the written contract terminated by HM4 Coho L.P. ("HM4"), a limited partnership formed by Hicks Muse on behalf of the Hicks, Muse, Tate & Furst Equity Fund IV, in December 1998, (2) breach of the oral agreements reached with HM4 on the restructured transaction in February 1999 and (3) promissory estoppel. The Company reached a settlement of the litigation in May, 2001, subject to approval of the United States Bankruptcy Court (the "Bankruptcy Court") and resolution of certain disputes relating to a matter under seal by order of the Bankruptcy Court as discussed below. Final settlement documents were signed during October 2001 and approved by the Bankruptcy Court in January 2002. The disputed termination issue discussed below has not been finalized so the final settlement has been extended until April 15, 2002. The Company does not expect the settlement to have a material impact on the Company's financial position or results of operations. Pursuant to the Company's plan of reorganization, shareholders as of February 7, 2000, are eligible to receive their pro rata share of 20% of the proceeds available from the Hicks Muse lawsuit settlement after fees and expenses. The Company has not yet determined the impact, if any, of its current bankruptcy proceedings on the distribution of these proceeds to shareholders. 66 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (d) During 2001, the Company became involved in a matter in connection with the lawsuit filed by the Company against Hicks Muse. This matter is under seal by order of the Bankruptcy Court. The matter involves a termination issue and the plaintiff claims damages that are based on a percentage of the ultimate amount recovered, if any, in the lawsuit against Hicks Muse. These percentages would be calculated on a graduated scale decreasing from 30% to 10% as the amount recovered increases. Alternatively, the plaintiff claims damages on the basis of lost time. However, the Company does not believe that either of these methods represents an appropriate measure of damages. The Company believes that the claim is without merit. At the order of the Bankruptcy Court, certain matters were arbitrated. The arbitration panel's sealed findings were forwarded to the Bankruptcy Court and considered in conjunction with the final settlement discussed above. The damages awarded are currently being appealed by the Company and the plaintiff. The Company does not expect this matter to have a material impact on its financial position or results of operations. Resolution of this matter may, however, impact the amount of proceeds available to the Company from the settlement of the Hicks Muse lawsuit. (e) On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of Hicks, Muse, Tate & Furst, filed a lawsuit against certain former officers of the Company alleging, among other things, such officers made or caused to be made false and misleading statements as to the proved oil and gas reserves purportedly owned by the Company. The plaintiffs are asking for compensatory damages of approximately $15 million plus punitive damages. Subsequently, the plaintiff named Ryder Scott Company and Sproule Associates Inc., the independent petroleum consultants which evaluate the Company's oil and gas reserves, as additional defendants. Pursuant to the Company's bylaws, the Company may be required to indemnify such former officers against damages incurred by them as a result of the lawsuit not otherwise covered by the Company's directors' and officers' liability insurance policy. The settlement of the Company's lawsuit against certain affiliates of Hicks, Muse, Tate & Furst, as described above, requires dismissal of the claims against the former officers. If the suit continues against Ryder Scott Company and Sproule Associates Inc., the Company may be required to indemnify these companies subject to their terms and conditions contained in certain agreements with them, however the Company does not expect this matter to have a material impact on the Company's financial position or results of operations. (f) The Company has leased (i) 26,751 square feet of office space in Dallas, Texas under a non-cancellable lease extending through December 2005, with a one time cancellation option during September 2003, (ii) 10,000 square feet of office space in Ratliff City, Oklahoma and (iii) surface leases in Laurel, Mississippi with expiration dates extending through the year 2018. Rental expense totaled $1,798,000, $1,394,000 and $687,000 in 1999, 2000 and 2001, respectively. Minimum rentals payable under these leases for each of the next five years are as follows: 2002 - $1,162,000; 2003 - $1,143,000; 2004 - $1,141,000; 2005 - $1,141,000 and 2006 - $492,000. Total rentals payable over the remaining terms of the leases are $3,445,000. (g) The Company has entered into employment agreements with certain of its officers. In addition to base salary and participation in employee benefit plans offered by the Company, these employment agreements generally provide for a severance payment in an amount equal to two times the rate of base annual compensation of the officer in the event there is a change of control or in the event the officer's employment is terminated for other than cause. The officers' aggregate annual compensation covered under such employment agreements is approximately $800,000. (h) The Company has entered into executive stay agreements with certain key employees which are designed to encourage these key employees to continue to carry out their duties with the Company in the event of a change in control of the Company. If the employee, subsequent to a change in control, continues to be employed by the Company for a period of not less than 180 days or if the employee's employment is terminated for other than cause, these stay agreements generally provide for a payment in an amount equal to 1.0 times the employees annual salary. The annual salary paid to the key employees covered under such severance agreements aggregates approximately $265,000. 67 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) 13. FINANCIAL INSTRUMENTS AND CREDIT RISK CONCENTRATIONS Financial instruments which are potentially subject to concentrations of credit risk consist principally of cash, cash equivalents and accounts receivable. Cash and cash equivalents are placed with high credit quality financial institutions to minimize risk. The carrying amounts of these instruments approximate fair value because of their short maturities. The Company has entered into certain financial arrangements which act as a hedge against price fluctuations in future crude oil and natural gas production. Included in operating revenues are realized losses of $0, $10,401,000 and $6,331,000 for 1999, 2000 and 2001, respectively, resulting from these hedging programs. In addition, realized losses of $313,000 for 2001 are included in loss on derivatives. At December 31, 2000 and 2001, the Company had no deferred hedging gains or losses. As of December 31, 2001, the Company had $2.1 million in net unrealized gains. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resoruces" for discussion on hedging arrangements. Fair values of the Company's financial instruments are estimated through a combination of management's estimates and by reference to quoted prices from market sources and financial institutions, if available. As of December 31, 2000, the fair market value of the Company's standby loan notes was $87.0 million compared to the related carrying value of $92.5 million. The carrying value of the credit facility and old bank group loan agreement approximated fair market value at December 31, 2000 since the applicable interest rate approximated the market rate. The carrying value of the standby loan notes and credit facility at December 31, 2001, excluding unamortized debt issuance costs, was $86.1 million and $195 million, respectively. Due to the default under these debt agreements in February 2002, the Company does not believe it is practicable to estimate the fair value of these debt instruments at December 31, 2001. During 1999, two purchasers of our crude oil and natural gas, EOTT and Amoco Production Company accounted for 39% and 41%, respectively, of the Company's revenue. During 2000, EOTT and Amoco Production Company accounted for 41% and 29%, respectively, of the Company's revenue. In October 2000, we began selling our crude oil that had been previously sold to Amoco, to TEPPCO Crude Oil, L.P. and Sunoco, Inc. During 2001, EOTT, TEPPCO Crude Oil, L.P. and Sunoco, Inc. accounted for 41%, 30% and 13%, respectively, of the Company's revenue. Included in accounts receivable is $114,000, $250,000 and $52,000 from these customers at December 31, 1999, 2000 and 2001, respectively. 14. RELATED PARTY TRANSACTIONS (a) In 1990, the Company made a non-interest bearing loan in the amount of $205,000 to Jeffrey Clarke, the Company's former President and Chief Executive Officer, to assist him in the purchase of a house in Dallas. The Company has entered into an executive employment severance agreement with Mr. Clarke in which he received a forbearance of the loan from the Company in exchange for his assistance in the Hicks Muse lawsuit. The loan will be forgiven on the date the Hicks Muse lawsuit is settled or otherwise completed. At March 31, 2000, the Company provided an allowance for this loan and charged reorganization expense. (b) On March 31, 2000, the Company issued $72 million of senior subordinated notes (see Note 5), of which $65.5 million were issued to the Company's major shareholders and their affiliates. In addition, participants purchasing the notes were entitled to a cash origination fee equal to 3 1/2% of the face amount of the notes purchased plus 2,694,841 shares of the Company's common stock. Share information, loan origination fees and notes purchased by the Company's major shareholders are as follows:

In addition, during April 2000, certain officers of the Company were entitled, pursuant to their employment contracts, to participate in the senior note loans and receive the benefit of the loan origination fee and additional shares of common stock issued by purchasing senior notes at face value from Appaloosa Management, L.P. and 68 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) PPM America, Inc. and affiliates. Share information, loan origination fees and senior notes purchased from the major shareholders by officers of the Company are as follows:

(c) The senior subordinated notes, as discussed in (b) above, require semiannual interest payments payable in cash or, if required pursuant to the intercreditor arrangement between the standby lenders and the lenders under the credit agreement, paid-in-kind (see Note 5). On September 29, 2000, March 30, 2001 and September 28, 2001, the semiannual interest payment of $5.4 million, $5.8 million and $10.3 million, respectively, were paid-in-kind to the holders of the senior subordinated notes, resulting in the issuance of new senior subordinated notes to certain major shareholders and officers as follows:

(d) The Company entered into an agreement with Pirinate Consulting Group, LLC with respect to monthly financial advisory services to be performed by Eugene Davis for the Company. The agreement called for a monthly retainer of $15,000 which began on April 1, 2000 and continued through August 2001, at which time the agreement was terminated. Mr. Davis is Chairman and Chief Executive Officer of Pirinate Consulting Group, LLC and is currently a director of the Company. 15. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)

69 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Basic per share figures are computed based on the weighted average number of shares outstanding for each period shown. Diluted per share figures are computed based on the weighted average number of shares outstanding including common stock equivalents, consisting of stock options and warrants, when their effect is dilutive. Quarterly financial data for 1999 and the first quarter of 2000 have been restated to reflect the conversion of old common stock to new common stock. 16. SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS ACTIVITIES Costs Incurred Costs incurred for property acquisition, exploration and development activities were as follows:

70 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Quantities of Oil and Gas Reserves (Unaudited) The following table presents estimates of the Company's proved reserves, all of which have been prepared by the Company's engineers and evaluated by independent petroleum consultants. See "Business and Properties - Reserves" for discussion on decrease in estimated reserves. Substantially all of the Company's crude oil and natural gas activities are conducted in the United States.

Standardized Measure of Oil and Gas Reserves (unaudited) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves. The following standardized measure of discounted future net cash flows was computed in accordance with the rules and regulations of the Securities and Exchange Commission and SFAS No. 69 using year end prices and costs, and year end statutory tax rates. Royalty deductions were based on laws, regulations and contracts existing at the end of each period. No values are given to unproved properties or to probable reserves that may be recovered from proved properties. The inexactness associated with estimating reserve quantities, future production and revenue streams and future development and production expenditures, together with the assumptions applied in valuing future production, substantially diminishes the reliability of this data. The values so derived are not considered to be an estimate of fair market value. The Company therefore cautions against this use. 71 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:

(a) Based on year end NYMEX prices. (b) 1999 prices were based on year end posted prices under our gas contracts. 2000 and 2001 prices were based on the year end NYMEX price of $9.78 per MMBTU and $2.57 per MMBTU, respectively. The following are the significant sources of changes in discounted future net cash flows relating to proved reserves:

72 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 73 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT BOARD OF DIRECTORS The names of our directors and other information with respect to each of them are set forth below. Each of these directors was appointed for a one year term or until the next annual meeting following the date of appointment. During August 2001, three directors advised us that they were resigning, effective immediately, as directors of Coho Energy, Inc. The board vacancies created by these directors have not been filled and due to our filing for protection under the bankruptcy code, these positions will remain vacant.

(a) Member of the Compensation Committee. (b) Member of the Audit Committee. (c) Chairman of the Audit Committee. (d) Chairman of the Compensation Committee. Michael Y. McGovern. Mr. McGovern has served as our President and Chief Executive Officer since April 1, 2000. Mr. Govern served as Managing Director of Pembrook Capital Corporation, an energy investment and advisory services company, from 1998 until March 31, 2000 and served as Chairman and Chief Executive Officer for Edisto Resources Corporation, a publicly held oil and gas company, from 1993 to 1997. Mr. Govern is a director of Greystar Corporation, a private production management service company; Pioneer Companies, Inc., a public manufacturing company of chlorine, caustic soda and related products; and Goodrich Petroleum Corporation, a public oil and gas company. Eugene I. Davis. Mr. Davis has served as Chairman and Chief Executive Officer of Pirinate Consulting Group, L.L.C., a consulting firm specializing in crisis and turn-around management advisory services for public and private businesses, since 1999. Mr. Davis served as Chief Operating Officer of Total-Tel USA Communications, Inc., an integrated telecommunications provider, from 1998 to 1999. He also served in various officer positions, recently as Chief Executive Officer of RBX Corp., a privately held manufacturer of rubber and plastic specialty products, since January 2001, and also as its Chairman since September 2001 and as Vice Chairman and Director, of Emerson Radio Corporation, an international distributor of consumer electronics products, from 1990 to 1997. Mr. Davis is a director of Eagle Geophysical Corporation, a privately held seismic company. Michael E. Salvati. Mr. Salvati is an independent financial consultant with Oak Ridge Consulting, Inc. Mr. Salvati also served as Chief Financial Officer of MarchFirst, a publicly held internet professional services company, during March and April 2001. During April 2001, MarchFirst filed for protection under Chapter 11 of the U.S. Bankruptcy Code and Mr. Salvati resigned. Mr. Salvati served as Executive Vice President and Chief Operating Officer of National Financial Partners Corp., a financial services firm, from 1998 to February 2000. Mr. Salvati served as Vice President and Chief Financial Officer of Culligan Water Technologies, Inc., from 1996 to 1998, and was a Partner with KPMG Peat Marwick LLP, a public accounting firm, prior to 1996. Mr. Salvati is a director of Prime Succession Inc., a privately held holding company of funeral homes; NCH Marketing Services, Inc., a privately held marketing services and coupon processing company; and Lazy Days' RV Center, Inc., a privately held retailer of recreational vehicles. There is no family relationship between any director, executive officer or person nominated or chosen by the registrant to become a director or executive officer. 74 EXECUTIVE OFFICERS The names of our executive officers and other information with respect to them are set forth below:

For information concerning Michael McGovern, see the table under the caption "Directors," above. Gary L. Pittman has served as our Chief Financial Officer and Corporate Secretary since April 1, 2000. Mr. Pittman served as Chief Financial Officer of Bell Geospace, Inc., a privately held technology based provider of high resolution gradient data to the oil and gas industry, from August 23, 1999 to March 17, 2000. Bell Geospace was a financial distress start-up company that engaged Mr. Pittman to assist in developing and executing a strategic business plan, which included filing bankruptcy on October 4, 1999. In March 2000, Bell Geospace filed its plan of reorganization and Mr. Pittman resigned. The court subsequently approved Bell Geospace's plan of reorganization on July 23, 2000. Mr. Pittman also served as a financial consultant to Perception, Inc., a privately held manufacturing company, from 1998 to 1999, and as Executive Vice President and Chief Financial Officer of Convest Energy Corporation, a publicly traded independent energy company, from 1995 to 1997. Gerald E. Ruley has served as our Vice President-Operations since April 1, 2000 and as a Production Manager for Coho since 1996. Mr. Ruley also served as Exploration and Production Manager of Winchester Production Company, an independent energy company, from 1994 to 1995. Susan J. McAden has served as our Controller and Chief Accounting Officer since April 1, 2000. Ms. McAden has been employed by us since February 1995 as Controller and was promoted to Vice President and Controller in January 1998. Messrs. McGovern and Pittman were directors and officers of two of Coho's wholly-owned subsidiaries that filed for protection under Chapter 11 of the United States Bankruptcy Code in February 2001 as discussed under Part I, Items 1 and 2. "Business and Properties-Oil and Gas Operations-Tunisian Operations." Mr. Ruley was also a director of these two wholly-owned subsidiaries. Mr. Ruley and Ms. McAden were officers of one of these two wholly-owned subsidiaries. ITEM 11. EXECUTIVE COMPENSATION The following tables contain information about our most highly compensated officers, including our Chief Executive Officer, in 1999, 2000 and 2001. SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE To our knowledge, based solely on a review of the copies of reports required pursuant to Section 16(a) of the Securities Exchange Act of 1934, as amended, that have been furnished to us and written representations that no other reports were required during the year ended December 31, 2001, all Section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% beneficial owners have been met except the Form 4 for Oaktree Capital Management, LLC related to its common shares sold on May 13, 2001 was not filed on a timely basis and the Form 4 for Oaktree Capital Management, LLC related to its common shares sold on August 31, 2001 was not filed on a timely basis. 75 SUMMARY COMPENSATION TABLE

(1) Mr. McGovern has served as our President and Chief Executive Officer since April 1, 2000. Mr. McGovern's All Other Compensation includes our contributions to a 401(k) savings plan of $8,500 in each of 2001 and 2000 and $95,414 related to relocation costs in 2000. (2) Mr. Ruley has served as our Vice President-Operations, Exploration, Land and Reserves since April 1, 2000. Mr. Ruley's All Other Compensation includes our contributions to a 401(k) savings plan of $8,500 in each of 2001 and 2000. Mr. Ruley did not serve as an executive officer during 1999. (3) Mr. Pittman has served as our Vice President, Chief Financial Officer and Corporate Secretary since April 1, 2000. Mr. Pittman's All Other Compensation includes our contributions to a 401(k) savings plan of $8,500 in 2001 and $7,500 in 2000 and $39,305 related to relocation costs in 2000. (4) Ms. McAden has served as our Controller and Chief Accounting Officer since April 1, 2000. Ms. McAden's All Other Compensation includes our contributions to a 401(k) savings plan of $8,500 in 2001 and $6,485 in 2000; premiums paid on a disability policy of $1,732 in 2001 and $1,614 in 2000; and claim settlement payments totaling $27,500 in 2001 and $82,500 in 2000 associated with the termination of her severance agreement in our March 2000 reorganization. No options were granted to any officers during 2001. AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUES

76 (1) Computed based upon the difference between the market price on December 31, 2001 of $0.01 per share and the exercise price per share. EMPLOYMENT AGREEMENTS On April 1, 2000, we entered into employment agreements with each of Messrs. McGovern, Ruley and Pittman, which provide for minimum annual compensation in the amount of $350,000, $250,000, and $200,000, respectively. Each employment agreement is for a term of two years, which term automatically renews daily for a term to extend two years from the renewal date until either party gives notice. Additionally, each employment agreement automatically terminates on the date of a "Change of Control," as defined below. Each employment agreement entitles the officer to participate in the bonus, incentive compensation and other programs that are created by our board of directors. If any of Messrs. McGovern, Ruley or Pittman is terminated by Coho without "Cause" (as defined below), or if the employment agreements are automatically terminated because of a "Change of Control," Coho would: o pay that individual a cash lump sum payment equal to two times the executive's then-current annual rate of total compensation; and o continue, until the second anniversary of the employment termination, health and life insurance coverage under our plans or the equivalent thereof on the same basis as our other senior executives. If any of Messrs. McGovern, Ruley or Pittman becomes disabled or dies during the term of the respective employment agreement, the employment agreement may be terminated by us, and we will pay the executive or his estate any unpaid compensation and other benefits under the employment agreement until the date of termination. The term "Cause" is defined in each employment agreement generally to mean: o any material failure of the executive after written notice to perform his or her duties; o commission of fraud, embezzlement or misappropriation by the executive against Coho; o a material breach by the executive of the employment agreement or of the fiduciary duty owed to Coho; or o conviction of the executive of a felony offense or a crime involving moral turpitude. Under each employment agreement, a "Change of Control" of Coho is deemed to have occurred if: o there is a sale, lease or other transfer of all or substantially all of the assets of Coho; o our shareholders adopt a plan relating to the liquidation or dissolution of Coho; o any person or group of persons acting in concert becomes the beneficial owner of more than 50 percent of the voting power of our securities generally entitled to vote in the election of directors, with certain exceptions; or o there occurs a merger or consolidation of Coho unless, after the transaction, all of those persons who were the beneficial owners of our common stock before the transaction beneficially own 50 percent or more of the total voting power of all securities generally entitled to vote in the election of directors, managers or trustees of the surviving entity. On April 3, 2000, we entered into an executive employment severance agreement with Jeffrey Clarke, our former president and chief executive officer. The purpose of this agreement was to compromise and settle any claims Mr. Clarke may have had under his prior employment agreement and to secure Mr. Clarke's assistance in the lawsuit we filed against Hicks Muse. In addition, Mr. Clarke agreed to serve as a consultant to us for up to two days per week through June 30, 2000. Under the compromise and settlement agreement, Mr. Clarke received a total of $875,000 as a cash settlement, $412,500 of which was paid in April 2000 and $462,500 of which was paid in 77 January 2001. We also agreed to pay two years of medical insurance, life insurance and disability insurance aggregating approximately $86,000 for the two year period. In addition, under the agreement, Mr. Clarke is entitled to the following non-cash benefits: o release of any claims we may have in connection with the non-interest bearing sole recourse loan made to Mr. Clarke in October 1997 to assist him in the exercise of expiring options; o forebearance of the interest-free loan from us to Mr. Clarke in the amount of $205,000 used to purchase a house, in exchange for Mr. Clarke's assistance in the Hicks Muse lawsuit, which loan will be forgiven on the date the Hicks Muse lawsuit is settled or otherwise concluded; o a three-year directors' and officers' insurance policy covering actions prior to the effective date of our March 2000 plan of reorganization; and o our agreement not to assign any claims we may have against Mr. Clarke, if any. Also on April 13, 2000, we entered into an agreement with Susan J. McAden, our Controller and Chief Accounting Officer, related to her former position as our Vice President and Controller, to compromise and settle her claim under her previous severance agreement, which was rejected under our March 2000 plan of reorganization. Under the compromise and settlement agreement, Ms. McAden received a $110,000 cash settlement, $82,500 of which was paid in 2000 and $27,500 of which was paid in January 2001. We have entered into an executive stay agreement with Ms. McAden which is designed to encourage her to continue to carry out her duties with us in the event we have a change in control. If she, subsequent to a change of control, continues to be employed by us for a period of greater than 180 days or if her employment is terminated for other than cause, this stay agreement generally provides for a payment in an amount equal to her annual salary. In March 2002, we filed two separate motions with the bankruptcy court requesting authorization to implement a senior management incentive retention program and a key employee retention program. These programs have not been approved by the bankruptcy court as of March 31, 2002. The following discussion describes the material terms of the retention programs as proposed. The senior management incentive retention program includes Messrs. McGovern, Pittman and Ruley. Consistent with the terms of their employment contracts, each will be entitled to receive stay retention payments totaling two times their annual base salaries until the earlier of: o the confirmation of a plan of reorganization; o the sale of substantially all of our assets; o our conversion to Chapter 7; or o their termination other than for cause. Any entitlement to payments for such officer will be forfeited if he resigns prior to the occurrence of one of these events. The key employee retention program includes Ms. McAden. Consistent with the terms of her executive stay agreement, she will be entitled to receive a stay retention payment equal to one year of her annual base salary upon the occurrence of the events previously listed under the senior management program and she is subject to the same forfeiture provision. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION At December 31, 2001, the members of our compensation committee were Michael E. Salvati, Eugene I. Davis and Michael Y. McGovern. Mr. McGovern has also served as our president and chief executive officer since 78 April 1, 2000. No other member of our compensation committee was an officer or employee of Coho at any time during 2001. During 2001, no executive officer of Coho served as: o a member of the compensation committee or other board committee performing equivalent functions (or, in the absence of any such committee, the board of directors) of another entity, one of whose executive officers served on the compensation committee of our board of directors; o director of another entity, one of whose executive officers served on the compensation committee of our board of directors; or o a member of the compensation committee or other board committee performing equivalent functions (or, in the absence of any such committee, the board of directors) of another entity, one of whose executive officers served as a director of Coho. COMPENSATION OF DIRECTORS Directors who are not our employees receive an annual retainer of $15,000 plus a fee of $1,000 for each meeting of our board of directors or meeting of a committee of our board of directors attended in person and $500 for each telephonic board meeting. Additionally, members of the Audit, Compensation and Executive Committees will receive an annual fee of $2,000, with the exception of the chairman of each Committee, who will receive an annual chairman fee of $3,500. All directors are reimbursed for expenses incurred in attending meetings of our board of directors or meetings of committees of our board of directors. Our employees who are also directors do not receive a retainer or fees for attending meetings of our board of directors or meetings of committees of our board of directors. On April 1, 2000, we entered into an agreement with Pirinate Consulting Group, LLC with respect to monthly financial advisory services to be performed by Eugene I. Davis for us for a monthly retainer of $15,000. This agreement was terminated effective August 31, 2001. Mr. Davis is Chairman and Chief Executive Officer of Pirinate Consulting Group, LLC and is currently one of our directors. NON-EMPLOYEE DIRECTOR STOCK OPTION PLAN On August 17, 2000, we adopted a non-employee director stock option plan for our current non-employee directors. On August 17, 2000, each non-employee director received options to purchase 10,000 shares of our common stock at a price per share equal to the closing sale price of our common stock on August 17, 2000. In addition, on August 1 of each year thereafter the directors are each entitled to receive options to purchase an additional 5,000 shares of our common stock at the closing sale price on the date of grant. Options granted under the non-employee director stock option plan are fully exercisable on the date of grant and must be exercised within five years from the date of grant. The options terminate on the earlier of the date of the expiration of the option or one year after the date the optionee ceases to serve as a director of Coho. REPORT OF THE COMPENSATION COMMITTEE WITH RESPECT TO COMPENSATION OF EXECUTIVE OFFICERS To the Board of Directors Coho Energy, Inc. OBJECTIVES The objective of the Compensation Committee is to develop compensation policies which will provide incentives to key executives to develop and carry out Coho's business strategy that will result in the maximization of return to the shareholders. More specifically, the Compensation Committee's objectives are to develop compensation policies which will: o allow Coho to attract and retain qualified individuals; 79 o encourage achievement of Coho's short term and long term goals; and o align executive remuneration with the interest of shareholders by linking a significant portion of executive compensation to the appreciation of the share price of the common stock. The Compensation Committee's philosophy toward executive compensation is to provide a combination of base level cash compensation and annual incentives, as well as providing longer term awards through a stock option plan. No stock options were granted to Messrs. McGovern, Pittman and Ruley during 2001. Executives are also permitted to participate in a health benefits insurance program and a 401 (k) plan, each of which is available to all employees of Coho. Base Compensation The minimum cash compensation levels set forth in the 2000 employment agreements for Messrs. McGovern, Ruley and Pittman were based on such factors as the executives' levels of responsibility, prior experience, breadth of knowledge and compensation paid to similarly situated executives employed by oil and gas companies with capitalizations similar to Coho and with experience in directing a company emerging from a bankruptcy reorganization. The Compensation Committee's review and analysis of these matters was subjective in nature, with no particular weight being placed on any specific factors. No adjustments were made to these compensation levels during 2001. Annual Incentives Although the employment agreements for Messrs. McGovern, Ruley and Pittman entitle them to participate in bonus and incentive compensation programs, no such programs have been implemented. Respectfully submitted, COMPENSATION COMMITTEE Michael E. Salvati Eugene I. Davis Michael Y. McGovern 80 PERFORMANCE GRAPH The following graph compares, as of December 31 for each of the dates indicated, the percentage change in cumulative total stockholder return on our common stock with the cumulative total return of the Standard & Poor's 500 Index and the Standard Industrial Code Index for Crude Oil and Natural Gas Producers. The graph assumes that the value of the investment in our common stock and each index was $100 at December 31, 1996 and that all dividends paid by those companies included in the indices were reinvested. [PERFORMANCE GRAPH] COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN* AMONG COHO ENERGY, INC., THE S&P 500 INDEX AND A PEER GROUP

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth information as to persons or entities who, to our knowledge based on information received from those persons or entities, were the beneficial owners of more than 5% of the outstanding shares of common stock as of March 15, 2002. Unless otherwise specified, these persons have sole voting power and sole dispositive power with respect to all shares attributable to them.

81 (1) Based on 18,714,175 shares issued and outstanding as of March 15, 2002. (2) Based on information contained in a Schedule 13D filed April 26, 2001 filed with the Commission. PPM America, Inc. has shared voting and dispositive power with respect to 6,721,076 shares of new common stock that are owned by it. (3) Based on information contained in Form 5 filed February 13, 2002 with the Commission. Oaktree Capital Management, LLC has sole voting and dispositive power with respect to 4,366,885 shares of Common Stock that are owned by it. (4) Based on information contained in a Schedule 13D filed December 18, 2001 filed with the Commission. Appaloosa Management, L.P. is a limited partnership and has sole voting and dispositive power with respect to 3,384,936 shares of new common stock that are owned by the partnership. The number of shares shown as beneficially owned includes the 20,000 shares that may be acquired upon the exercise of stock options held by two former directors for the benefit of Appaloosa Management, L.P. The following table sets forth information with respect to common stock beneficially owned as of March 15, 2002 by each of our directors, by each executive officer named in the Summary Compensation Table and by all directors and officers as a group. Unless otherwise specified, these persons have sole voting power and sole dispositive power with respect to all shares attributable to him or her.

* Less than 1% (1) Based on 18,714,175 shares issued and outstanding as of March 15, 2002. (2) Includes 15,000 shares that may be acquired upon exercise of stock options held by each of Mr. Davis and Mr. Salvati. (3) The numbers of shares shown as beneficially owned by Messrs. McGovern, Pittman and Ruley include 560,825, 233,677, and 186,942 shares, respectively, that may be acquired upon exercise of stock options within 60 days. Included in Mr. Ruley's total shares are 1,496 shares which are held by a family trust; Mr. Ruley disclaims any beneficial ownership interest in these shares. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS On March 31, 2000, and in connection with the consummation of our March 2000 plan of reorganization, we issued $72 million of senior subordinated notes, of which $65.5 million were issued to three of our major shareholders and their affiliates. In addition, participants purchasing the notes were entitled to a cash origination fee equal to 3 1/2% of the face amount of the notes purchased plus an aggregate of 2,694,841 shares of our common stock. Share information, loan origination fees and notes purchased by our major shareholders are as follows: 82

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

The senior subordinated notes, as discussed above, require semiannual interest payments payable in cash or, if required pursuant to the intercreditor arrangement between the standby lenders and the lenders under our bank credit agreement, paid-in-kind. On September 29, 2000, March, 30, 2001 and September 28, 2001, the semiannual interest payment of $5.4 million, $5.8 million and $10.3 million, respectively, were paid-in-kind to the holders of the senior subordinated notes, resulting in the issuance of new senior subordinated notes to certain major shareholders and officers as follows:

On April 1, 2000, we entered into an agreement with Pirinate Consulting Group, LLC with respect to monthly financial advisory services to be performed by Eugene I. Davis for us for a monthly retainer of $15,000. This agreement was terminated effective August 31, 2001. Mr. Davis is Chairman and Chief Executive Officer of Pirinate Consulting Group, LLC and is currently one of our directors. We have entered into executive stay agreements with certain key employees which are designed to encourage these key employees to continue to carry out their duties with us in the event we have a change in control. If the employee, subsequent to a change in control, continues to be employed by us for a period of greater than 180 days or if the employee's employment is terminated for other than cause, these stay agreements generally provide for a payment in an amount equal to the employee's annual salary. The change of control payments paid to the key employees covered under such severance agreements would aggregate approximately $406,000. Pursuant to a registration rights agreement dated March 31, 2000, we have agreed to register all shares of our common stock owned, currently or in the future, by PPM, Appaloosa, Oaktree and Pacholder Associates, Inc. In accordance with the registration rights agreement, we have filed a shelf registration statement which became effective on January 8, 2001 and have agreed to keep the shelf registration statement effective until the earlier of 83 three years from the date of effectiveness or the time when the shares of common stock covered by the registration rights agreement have been sold or may be sold without restriction. We have a limited right to suspend the availability of the shelf registration statement for a valid business purpose for up to two consecutive 30-day periods or to prevent the disclosure of material non-public information. Due to our default under the senior credit facility, the shelf registration statement is currently not available. Further, holders of at least 10% of all common stock covered by the registration rights agreement may request that we register shares for sale in the manner specified in the request. Each of PPM, Appaloosa, Oaktree and Pacholder is entitled to three demand registrations. However, they may request a registration on Form S-3 and if Form S-3 is available to us, there is no limit on the number of registrations on Form S-3 that we are obligated to effect. We have a limited right to delay the filing of a registration statement pursuant to these demands to prevent the disclosure of material non-public information. In addition, any time we file a registration statement, holders of common stock covered by the registration rights agreement will have the right to request the inclusion of their shares in the registration. The number of shares requested to be registered (except those under the shelf registration statement) may be cut back, on a pro rata basis, by the managing underwriter in a public offering to ensure the successful marketing of a smaller number of shares. 84 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Documents Filed as a Part of this Report 1. FINANCIAL STATEMENTS Reference is made to the Index to Financial Statements under Item 8 on page 41. 2. FINANCIAL STATEMENT SCHEDULES All schedules and financial statements are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto listed above in Item 14(a) 1. 3. EXHIBITS EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 - Amended and Restated Articles of Incorporation of the Company (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 3.2 - Amended and Restated Bylaws of the Company (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.1 - Credit Agreement dated as of March 31, 2000, among Coho Energy, Inc., The Chase Manhattan Bank, Meespierson Capital Corp., Fleet National Bank, Credit Lyonnais, New York Branch, ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.2 - First Amendment to Credit Agreement dated November 27, 2000 among Coho Energy, Inc., The Chase Manhattan Bank, Meespierson Capital Corp., Fleet National Bank, Credit Lyonnais, New York Branch, ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.3 - Registration Rights Agreement dated as of March 31, 2000, among Coho Energy, Inc., PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Management L.P., as agent and on behalf of certain funds including Appaloosa Investment Limited Partnership I, Palomino Fund Ltd., and Tersk LLC; Pacholder Associates, Inc., as agent and on behalf of certain funds including Pacholder Value Opportunity Fund, L.P., High Yield Fund, Inc., One Group High Yield Bond and Evangelical Lutheran Church in America Board of Pensions; and Oaktree Capital Management, LLC, as general partner of an investment manager for the entities set forth therein (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.4 - Note Agreement dated as of March 31, 2000 among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana Production Company, Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Investment Limited Partnership I, Palomino Fund Ltd., Tersk LLC, Oaktree Capital Management, LLC, Pacholder Value Opportunity Fund, L.P., Pacholder High Yield Fund, Inc., One Group High Yield Bond Fund, and Evangelical Lutheran Church in America Board of Pensions (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 85 10.5 - Securities Purchase Agreement dated as of March 31, 2000, among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana Production Company, Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Management, L.P., Oaktree Capital Management, LLC, and Pacholder Associates, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). * 10.6 - Employment Agreement dated as of April 1, 2000 by and among Michael Y. McGovern and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). * 10.7 - Employment Agreement dated as of April 1, 2000 by and among Gary L. Pittman and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). * 10.8 - Employment Agreement dated as of April 1, 2000 by and among Gerald E. Ruley and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). * 10.9 - Form of Stay Agreement entered into with each of Charles E. Gibson and Susan J. McAden (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.10 - Crude Oil Purchase Contract dated January 25, 1996, by and between Coho Marketing and Transportation, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.11 - Adoption Agreement for Coho Resources, Inc.'s Amended and Restated 401(k) Savings Plan dated July 1, 1995 (incorporated by reference to Exhibit 10.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10.12 - Letter Agreement dated March 5, 1999, by and between Coho Marketing and Transportation, Inc. and Eott Energy Operating Limited Partnership, amending the Crude Oil and Purchase Contract dated January 25, 1996, by and between Coho Marketing and Transportation, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to Exhibit 10.27 to the Company's Registration Statement on Form S-1 (Registration Statement No. 333-96331)). 10.13 - Crude Oil Purchase Agreement dated October 1, 2000, by and between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M) (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.14 - Crude Oil Purchase Agreement dated September 20, 2000, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P. (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.15 - Crude Oil Purchase Contract dated December 19, 2000, by and between Coho Resources, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.16 - Letter agreement dated November 30, 2001, by and between Coho Resources, Inc. and EOTT Energy Operating Limited Partnership, amending the crude oil purchase contract dated December 19, 2000, by and between Coho Resources, Inc. and EOTT Energy Operating Limited Partnership. 10.17 - Letter Agreement dated September 9, 2001 by and between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M), amending the crude oil purchase agreement dated October 1, 2000, by and between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M). 86 10.18 - Fifth Amendment to Crude Oil Purchase Agreement dated November 5, 2001, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P., amending the crude oil purchase agreement dated September 20, 2000, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P. 10.19 - Second Amendment to Credit Agreement dated April 20, 2001 among Coho Energy, Inc., The Chase Manhattan Bank, Fortis Capital Corp., Fleet National Bank, Credit Lyonnais, New York Branch, ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE. 10.20 - Letter Agreement dated November 16, 2001, by and between Coho Energy, Inc. and CIBC World Markets Corp. 10.21 - Non-employee Director Option Plan. 21.1 - List of Subsidiaries of the Company (filed herewith). 99.1 - Letter dated April 5, 2002 to the United States Securities and Exchange Commission regarding December 31, 2001 year-end audit performed by Arthur Andersen. * Represents management contract or compensatory plan or arrangement. The Company will furnish a copy of any exhibit described above to any beneficial holder of its securities upon receipt of a written request therefor, provided that such request sets forth a good faith representation that as of the record date for the Company's 2002 Annual Meeting of Shareholders, such beneficial holder is entitled to vote at such meeting, and upon payment to the Company of a fee compensating the Company for its reasonable expenses in furnishing such exhibits. (b) Reports on Form 8-K None. 87 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Coho Energy, Inc. Date: April 5, 2002 By: /s/ MICHAEL MCGOVERN ------------------------------------- Michael Y. McGovern President and Chief Executive Officer Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

88 INDEX TO EXHIBITS

10.5 - Securities Purchase Agreement dated as of March 31, 2000, among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana Production Company, Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Management, L.P., Oaktree Capital Management, LLC, and Pacholder Associates, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.6 - Employment Agreement dated as of April 1, 2000 by and among Michael Y. McGovern and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.7 - Employment Agreement dated as of April 1, 2000 by and among Gary L. Pittman and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.8 - Employment Agreement dated as of April 1, 2000 by and among Gerald E. Ruley and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.9 - Form of Stay Agreement entered into with each of Charles E. Gibson and Susan J. McAden (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.10 - Crude Oil Purchase Contract dated January 25, 1996, by and between Coho Marketing and Transportation, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.11 - Adoption Agreement for Coho Resources, Inc.'s Amended and Restated 401(k) Savings Plan dated July 1, 1995 (incorporated by reference to Exhibit 10.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10.12 - Letter Agreement dated March 5, 1999, by and between Coho Marketing and Transportation, Inc. and Eott Energy Operating Limited Partnership, amending the Crude Oil and Purchase Contract dated January 25, 1996, by and between Coho Marketing and Transportation, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to Exhibit 10.27 to the Company's Registration Statement on Form S-1 (Registration Statement No. 333-96331)). 10.13 - Crude Oil Purchase Agreement dated October 1, 2000, by and between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M) (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.14 - Crude Oil Purchase Agreement dated September 20, 2000, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P. (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.15 - Crude Oil Purchase Contract dated December 19, 2000, by and between Coho Resources, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 2000). 10.16 - Letter agreement dated November 30, 2001, by and between Coho Resources, Inc. and EOTT Energy Operating Limited Partnership, amending the crude oil purchase contract dated December 19, 2000, by and between Coho Resources, Inc. and EOTT Energy Operating Limited Partnership. 10.17 - Letter Agreement dated September 9, 2001 by and between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M), amending the crude oil purchase agreement dated October 1, 2000, by and between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M).

10.18 - Fifth Amendment to Crude Oil Purchase Agreement dated November 5, 2001, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P., amending the crude oil purchase agreement dated September 20, 2000, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P. 10.19 - Second Amendment to Credit Agreement dated April 20, 2001 among Coho Energy, Inc., The Chase Manhattan Bank, Fortis Capital Corp., Fleet National Bank, Credit Lyonnais, New York Branch, ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE. 10.20 - Letter Agreement dated November 16, 2001, by and between Coho Energy, Inc. and CIBC World Markets Corp. 10.21 - Non-employee Director Option Plan. 21.1 - List of Subsidiaries of the Company (filed herewith). 99.1 - Letter dated April 5, 2002 to the United States Securities and Exchange Commission regarding December 31, 2001 year-end audit performed by Arthur Andersen.

* Represents management contract or compensatory plan or arrangement.

COHO ENERGY INC 10-K