-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, DJhaSUe2koX8X5lPSDu8vxlYoZUMpDtt5EJk6zVj/BE2pXYPEy7NunPXbBtLp2z0 ZnTz9KWSx8jtViD66sl+aA== 0000950134-01-002955.txt : 20010402 0000950134-01-002955.hdr.sgml : 20010402 ACCESSION NUMBER: 0000950134-01-002955 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: COHO ENERGY INC CENTRAL INDEX KEY: 0000908797 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752488635 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-22576 FILM NUMBER: 1587920 BUSINESS ADDRESS: STREET 1: 14785 PRESTON RD STREET 2: STE 860 CITY: DALLAS STATE: TX ZIP: 75240 BUSINESS PHONE: 9727748300 MAIL ADDRESS: STREET 1: 14785 PRESTON RD STREET 2: SUITE 860 CITY: DALLAS STATE: TX ZIP: 75240 10-K 1 d85560e10-k.txt FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2000 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______to ________. Commission file number 0-22576 COHO ENERGY, INC. (Exact name of registrant as specified in its charter) Texas 75-2488635 - ------------------------------- ---------------------- (State or other jurisdiction of (IRS Employer incorporation or organization) Identification Number) 14785 Preston Road, Suite 860 Dallas, Texas 75240 - ---------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (972) 774-8300 -------------- Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, par value $0.01 per share Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] As of March 23, 2001, 18,714,175 shares of the registrant's Common Stock were outstanding and the aggregate market value of all voting stock held by non-affiliates was $10.7 million based upon the closing price on Nasdaq's OTC Bulletin Board on such date. The officers and directors of the registrant are considered affiliates for purposes of this calculation. INCORPORATION OF DOCUMENTS BY REFERENCE Portions of Coho Energy, Inc.'s definitive proxy statement relating to the registrant's 2001 annual meeting of shareholders, which proxy statement will be filed under the Securities Exchange Act of 1934 within 120 days of the end of the registrant's fiscal year ended December 31, 2000, are incorporated by reference into Part III of this Form 10-K. 2 TABLE OF CONTENTS
PAGE ---- PART I Item 1. Business.....................................................................................4 Item 2. Properties...................................................................................4 Item 3. Legal Proceedings...........................................................................22 Item 4. Submission of Matters to a Vote of Security Holders.........................................23 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters......................24 Item 6. Selected Financial Data....................................................................25 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations......................................................................26 Item 7A. Quantitative and Qualitative Disclosure about Market Risk..................................39 Item 8. Consolidated Financial Statements..........................................................41 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......................................................................65 PART III Item 10. Directors and Executive Officers of the Registrant.........................................66 Item 11. Executive Compensation.....................................................................66 Item 12. Security Ownership of Certain Beneficial Owners and Management.............................66 Item 13. Certain Relationships and Related Transactions.............................................66 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................67
2 3 FORWARD-LOOKING STATEMENTS This Form 10-K includes statements that may be deemed to be "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, project, believe or anticipate will or may occur in the future, including: o crude oil and natural gas reserves; o future acquisitions; o future drilling and operations; o future capital expenditures; o future production costs; o future production of crude oil and natural gas; o future economic performance; and o future net cash flow of proved oil and natural gas reserves are forward-looking statements. These forward-looking statements are generally accompanied by words such as "intend," "anticipate," "believe," "estimate," "expect," "should" or similar expressions. These statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Important factors that could cause actual results to differ materially from our estimates or projections include, among others, the following: o the highly competitive nature of the oil and gas exploration and production business; o the timing and success of our exploration and development drilling programs, which would affect production levels and reserves; o changes to our estimates of oil and gas reserves; o the risk that our earnings may be adversely affected by fluctuating energy prices; o the business opportunities, or lack thereof, that may be presented to and pursued by us; o risks incident to the drilling and operation of oil and gas wells, including environmental liabilities; o the substantial amount of our long-term indebtedness; and o other factors, many of which are beyond our control. These types of statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. You should not rely on this information as an estimate or prediction of future performance. DEFINITIONS See Page 8 for a list of definitions of certain industry terms used throughout this document. 3 4 PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES GENERAL Coho Energy, Inc. is an independent energy company engaged, through its wholly owned subsidiaries, in the development and production of, and exploration for, crude oil and natural gas. Our crude oil activities are concentrated principally in Mississippi and Oklahoma. At December 31, 2000, our total proved reserves were 100.8 MMBOE with a net present value of proved reserves discounted at 10% of $756.6 million, approximately 69% of which were proved developed reserves, based on year end market prices of $26.80 per barrel for crude oil and $9.78 per MMbtu for natural gas. Market prices for crude oil and natural gas have fluctuated significantly over the last three years. These year end market prices are high in comparison to historical average crude oil and natural gas prices in the most recent three-year period. Approximately 95% of our total proved reserves were comprised of crude oil. At December 31, 2000, our operations were conducted in 19 major producing fields, 16 of which we operated. Our average working interest in the fields we operate was approximately 80%. We were incorporated in June 1993 under the laws of the State of Texas and conduct a majority of our operations through our subsidiary Coho Resources, Inc. References in this Form 10-K to "Coho," "we," "our," or "us", except as otherwise indicated, refer to Coho Energy, Inc. and our subsidiaries. Our principal executive office is located at 14785 Preston Road, Suite 860, Dallas, Texas 75240, and our telephone number is (972) 774-8300. OUR HISTORY Mississippi. We commenced operations in Mississippi in the early 1980s and have focused most of our development efforts in that area. The salt basin in central Mississippi offered significant long-term potential due to the basin's large number of mature fields with multiple oil and gas producing sands. The application of proven technology to these underexploited and underexplored fields yielded attractive, lower-risk exploitation and exploration opportunities. As a result of the attractive geology and our experience in exploiting fields in the area, we have accumulated an inventory of potential development drilling, secondary recovery and exploration projects in this basin. Oklahoma. One of our business strategies has been to acquire additional properties with geologically complex environments and features similar to our Mississippi properties and to fully exploit the acquired properties using our substantial knowledge base and geological expertise gained from our historical success in Mississippi. In December 1997, we acquired properties from Amoco Production Company that we believed presented the exploitation opportunity we were seeking. The properties we acquired from Amoco Production Company had approximately 55 MMBOE total proved reserves and represented interests in more than 40,000 gross acres, concentrated primarily in southern Oklahoma, including 12 principal producing fields. We paid $260.9 million in cash and stock warrants to acquire these properties. Reorganization. On August 23, 1999, we and our wholly-owned subsidiaries, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production Company and Interstate Natural Gas Company, filed a voluntary petition for relief under Chapter 11 of the U. S. Bankruptcy Code. We then filed a plan of reorganization that was confirmed by the bankruptcy court on March 20, 2000. On March 31, 2000, the plan of reorganization was consummated and we emerged from bankruptcy. The plan of reorganization included the following transactions to complete the restructuring of our indebtedness: o The borrowing of $183.0 million under our new revolving credit facility with a new bank group. o The borrowing of $72.0 million under subordinated notes referred to as the standby loan, maturing March 2007. We also issued 2,694,841 shares of new common stock, representing 14.4% of our new common stock, as debt issuance costs to the lenders under these notes. 4 5 o The repayment of borrowings and interest due under the old bank credit facility. o Conversion of the old bonds into 15,362,107 shares of new common stock, representing 82% of our new common stock. As a result of the reorganization, our former principal bondholders and their affiliates own approximately 88% of our new common stock and own $65.5 million of the outstanding notes issued under our $72 million standby loan. Please read "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Credit Facilities" for a description of the terms of the standby loan. BUSINESS STRATEGY Our strategy is to increase the value of our proved reserves, thereby increasing shareholder value, by: o focusing on relatively low-risk development activities, such as development and delineation drilling, multi-zone recompletions, enhancement and/or expansion of existing secondary recovery projects that we expect to generate increases in production and cash flow from operations; o using these low-risk activities to increase our proved developed producing reserves by developing our proved undeveloped reserves; o increasing total proved reserves through the initiation of new secondary recovery projects in our existing fields and through the use of 2-D and 3-D seismic and other technologies to identify exploration projects which we expect will generate new reserves if our exploration efforts are successful; and o improving our production performance by installing specialized equipment, performing preventative equipment maintenance and conducting more extensive well repairs to wells that have failed in order to gain added run time in the future and as a result to achieve lower operating costs and less downtime for well repairs in the future. In connection with our reorganization in bankruptcy and related operational restructuring effective March 31, 2000, a new management team and a new board of directors were selected by our former principal bondholders to lead us as we emerged from bankruptcy. In addition to developing our business strategy, the new management team has: o developed a detailed operating plan through December 2001 to implement our business strategy with a continuing development plan into 2002; o assembled the personnel required to execute our operating plan and eliminated unnecessary positions; and o began implementing this operating plan. During the first 90 days following our emergence from bankruptcy, our management team substantially completed the development of our operating plan, including detailed business plans for each of our major fields, and the selection of personnel. We commenced implementing the capital expenditure projects identified in the operating plan in late June 2000. 2000 Capital Expenditures. During 2000, we incurred capital expenditures of $25.3 million. We directed our initial capital expenditures to capital projects that were expected to generate the largest ultimate increase in production and cash flow from operations. We expended approximately 60% of our initial capital expenditures on projects in our Mississippi fields and we spent the remaining 40% on projects in our Oklahoma fields. Approximately 70% of these capital expenditures was spent on recompletions, workovers and waterflood projects on existing wells to enhance production. Our expenditures for the drilling of new wells were modest during 2000 because drilling did not begin under our new operating plan until late in the second quarter of 2000 and rig availability was limited during the third and fourth quarters. During 2000, we drilled three wells in Mississippi, 19 wells in Oklahoma and participated in the drilling of one outside operated well in Oklahoma, including: o one deepening drilled in the first quarter; 5 6 o three wells drilled in the second quarter; o nine wells drilled in the third quarter; and o ten wells drilled in the fourth quarter. Of these 23 wells, nineteen were completed as producing wells, three gas wells and 16 oil wells. Three of the other four wells were dry holes, two low cost gas wells in Oklahoma and one exploratory oil well in Mississippi, and the remaining well was completed as a water injection well. We also had two wells drilling in Mississippi and three wells drilling in Oklahoma at year end. 2001 Capital Expenditures. We have budgeted $40.2 million for capital expenditures during 2001, of which approximately 70% is planned for projects in the first half of the year. We have drilled or plan to drill 12 wells in the first quarter of 2001 in addition to the five wells that were drilling at year end. The emphasis of our 2001 capital expenditure program is on: o the development of our East Velma Middle Block waterflood project; o infill drilling and waterflood projects in our East Fitts and Tatums fields; o continued development of our pilot waterflood projects that were started in 2000 in the Graham Deese, North Alma Deese and Jennings Deese units; and o further development drilling in several of our Mississippi fields, including the Brookhaven, Laurel, Martinville and Soso fields. These projects are discussed more fully under "Oil and Gas Operations." Operating Plan. We have a high level of indebtedness after the reorganization. Our total consolidated indebtedness as of December 31, 2000 was $282.4 million and the ratio of total consolidated indebtedness to total capitalization was 82%. Due to our high level of indebtedness, our operating plan during 2000 and 2001 focuses on capital projects that should generate increases in: o production; o cash flow from operations; and o proved developed producing crude oil and natural gas reserves and, to a lesser extent, total proved reserves. The majority of our capital expenditures during 2000 and 2001 are allocated to projects that are classified as proved undeveloped and proved non-producing projects in our reserve report. Our field development projects include the following activities to maximize production and increase proved developed producing reserves: o recompletions; o enhancement of production facilities; o installment of new waterflood projects; o expansion of existing waterflood injection projects; o installment of pump off controllers to improve lift efficiency; o multi-zone completions; and o development/delineation drilling. 6 7 Although total reserves may not increase substantially as a result of this work, the value of proved developed producing reserves and cash flow from operations should increase if these projects are successful, thereby increasing the value of our reserves in the banks' valuation analysis in determining our borrowing capacity and also increasing shareholder value. Our 2001 operating plan includes some exploration prospects in the vicinity of our existing fields using technologies that include 3-D seismic technology. 3-D seismic technology is a tool that allows us to look at vertical cross-sections as well as horizontal cross-sections beneath the prospective area of our properties on a very small grid pattern. We first began using 3-D seismic technology in the Laurel field in Mississippi in 1983, and have shot two large 3-D seismic programs in and around our existing properties in Mississippi within the last five years. At the time of purchase, we acquired four 3-D seismic programs in and around our Oklahoma properties. These programs have produced an attractive inventory of exploration projects that will increase total reserves if these projects are successful. Recapitalization. As previously described above, we are highly leveraged with a ratio of total consolidated indebtedness to total capitalization of 82%. Although we believe we currently have adequate sources of liquidity for the budgeted activities that we expect to conduct in 2001, this high level of indebtedness has several important effects on our future operations, including: o requiring us to devote a substantial portion of our cash flow from operations to pay interest on our indebtedness and not for other uses, such as funding working capital or capital expenditures; o limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes thereby restricting our future growth; o putting us at a competitive disadvantage to our competitors who have less debt than us; and o limiting our flexibility to plan for, or to react to, changes in our business and the oil and gas industry. We are exploring alternatives to reduce our leverage ratio. Our alternatives include, but are not limited to: o entering into an equity transaction with another company with a lower leverage ratio; o raising additional equity to repay all or a substantial portion of our indebtedness outstanding under the standby loan; o converting all or a substantial portion of the standby loan to equity; or o combining one or more of these various alternatives. Discontinuation of Tunisian Operations. We have decided to discontinue our participation in the exploration of two Tunisia, North Africa permits due to required capital commitments during 2001 exceeding $7 million net to our interest. Our two subsidiaries that own these permits, Coho Anaguid, Inc. and Coho International Limited, filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001 to preserve our ownership in these permits under the protection of the bankruptcy court while we attempt to negotiate sales of our interests in the permits to a third party or parties and to reach settlements with respect to our obligations under the permits. See "Oil and Gas Operations" for further discussion. 7 8 DEFINITIONS Unless otherwise indicated, natural gas volumes are stated at the legal pressure base of the State or area in which the reserves are located at 60 degrees Fahrenheit. The following definitions apply to the technical terms used in this Form 10-K: "2-D seismic" means an interpretive data set that allows a view of a vertical cross-section beneath a prospective area. "3-D seismic" means an interpretive data set that allows a view of a vertical cross-section as well as a horizontal cross-section beneath a prospective area. "Bbls" means barrels of crude oil, condensate or natural gas liquids, and is equivalent to 42 U.S. gallons. "Bcf" means billions of cubic feet. "BOE" means barrel of oil equivalent, assuming a ratio of six Mcf to one Bbl. "BOPD" means Bbls per day. "Developed acreage" means acreage which consists of acres spaced or assignable to productive wells. "Dry hole" means a well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well. "Gravity" means the Standard American Petroleum Institute method for specifying the density of crude petroleum. "Gross" means the number of wells or acres in which we have an interest. "MBbls" means thousands of Bbls. "MBOE" means thousands of BOE. "Mcf" means thousands of cubic feet. "MMBbls" means millions of Bbls. "MMBOE" means millions of BOE. "MMbtu" means millions of British Thermal Units. "MMcf" means millions of cubic feet. "Net" is determined by multiplying gross wells or acres by our working interest in such wells or acres. "Present value of proved reserves" means the present value discounted at 10% of estimated future net cash flows before income taxes of proved crude oil and natural gas reserves. "Productive well" means a well that is not a dry hole. "Proved developed reserves" means only those proved reserves expected to be recovered from existing completion intervals in existing wells and those proved reserves that exist behind the casing of existing wells when the cost of making those proved reserves available for production is relatively small relative to the cost of a new well. "Proved reserves" means natural gas, crude oil, condensate and natural gas liquids on a net revenue interest basis, found to be commercially recoverable. "Proved undeveloped reserves" means those reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. 8 9 "Recompletion" means leaving one formation for another formation within a well bore. "Secondary recovery" means a method of oil and natural gas extraction in which energy sources extrinsic to the reservoir are used. "Undeveloped acreage" means leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether or not that acreage contains proved reserves. "Unitized" means the royalty and working interests are pooled within a given geological and/or geographical area. "Waterflood" means the injection of water into oil bearing formations to displace the oil. "Workover" means the performing of work within a well bore associated with the currently producing formation. OIL AND GAS OPERATIONS General. In the conduct of our operations, we apply the latest developments in technology, completion and production techniques, and we employ new innovations in equipment to enhance exploitation, secondary recovery and exploration activities on oil and gas properties. The detailed application of these areas of our expertise to older properties has played an important role in our continuing production and reserve development. In 2000, we have conducted our operations mainly on the following fields: o Mississippi - Brookhaven, Martinville and Soso o Oklahoma - Tatums, East Fitts, East Velma Middle Block, Eola, North Alma Deese and Graham Deese Our capital expenditures totaled $6.3 million in 1999 and $25.3 million in 2000. We kept our 1999 capital expenditures very low due to budget constraints resulting from the substantial decline in crude oil prices in 1998 and early 1999, as well as expenditure constraints imposed by the bankruptcy court subsequent to August 23, 1999. In mid-year 2000, we resumed our development drilling program and drilled a total of 22 gross or 14.8 net development wells with a success rate of 90%. Initial combined net production rates from our development drilling totaled 626 net BOE per day. This development drilling also resulted in the reclassification of reserves from proved undeveloped reserves to proved developed producing reserves. Well repair and recompletion activity in 2000 enabled us to complete in excess of 200 workover and repair operations and 95 recompletions. We plan to continue this activity in 2001, and efforts are being concentrated to steadily make more extensive repairs to wells that have failed in order to gain added run time and ultimately reduce operating costs. Exploitation. Our properties are generally characterized as being mature and having multiple layers of oil and gas reservoirs, which are broken into numerous separate sources of supply due to the complex geology in many of the fields in which we operate. Our properties have a large number of wells that either we or other operators have drilled over the past 50 years. The data from this number of wells assists us in developing detailed geologic interpretations of our active regions, which continue to improve our understanding of the numerous hydrocarbon deposits on these properties. The changing economics of the value of these multiple reservoirs coupled with the ability to deploy capital and improved technology to identify and develop these sources of supply, presents us with new opportunities to produce reserves that were previously unattractive, unrecognized as productive or found to be isolated from the existing producing wells on a property. One of the key elements in our strategy of building reserves and creating shareholder value has been to concentrate on the full development of mature fields, which exhibit the potential for having been either underdeveloped or having further exploration opportunities through the utilization of new or existing technology. Secondary Recovery. The mature nature of our producing properties has provided us with opportunities to employ secondary recovery techniques to increase the recovery of reserves in place that have not been recovered by primary production means. In the majority of situations, the existing wells are utilized for this purpose, which greatly reduces the capital outlays otherwise necessary to connect to these sources of production. In addition, the water produced from these operations is re-injected into the reservoir creating a so-called water-drive mechanism to 9 10 extract the oil which was not produced under primary means. These projects have historically demonstrated strong production response and meaningful reserve additions. We have identified 20 potential secondary projects in Mississippi. We have successfully developed six of these projects and are in the process of installing one additional new secondary project at this time. The acquisition of the Oklahoma properties in 1997 presented us with nine existing secondary projects and we have identified 11 additional potential secondary projects on these properties. We have commenced a secondary project on the East Velma Middle Block Unit, which has been successfully performed by other operators on both sides of our property. Completion of the first phase of the installation is scheduled in the first half of 2001. We are continuing to improve recoveries on existing secondary projects by carefully monitoring the waterflood response to improve the sweep efficiency on these projects. As an example, we have launched pilot waterflood projects within our existing active waterflood projects in the Brookhaven field, Graham Deese Unit, North Alma Deese Unit, Jennings Deese Unit and Tatums Unit. Our infield development program is in association with the pilot waterflood project on the Tatums Unit. We plan to continue such pilot projects until we see sufficient encouragement to expand the pilot waterflood projects to the other parts of the field where indications are that the results will be attractive. Exploration. The complex geology of many of our oil and gas properties provides us with the opportunity to drill for new sources of supply within the area of our existing properties and to utilize the existing well control to substantially reduce dry hole risk. In order to further define our targets and assist in the geologic interpretation of these complex features, we have completed two 3-D seismic surveys in Mississippi, and are in the process of evaluating approximately 95 square miles of 3-D seismic data and 2,750 miles of 2-D seismic data acquired along with the Oklahoma properties. 2-D seismic data is a tool that allows us to look at vertical cross-sections beneath the prospective area of our properties typically on a much wider grid pattern. A 3-D seismic survey is a computer enhanced seismic survey that allows us to look at subsurface structures in an area in a three dimensional view and provides much greater detail and resolution of the geologic picture than using 2-D seismic data alone. This seismic data as well as our geologic interpretations has provided us with several prospective drilling opportunities, which are being further evaluated. In 2000, we drilled an exploratory step-out well on an untested fault block in the Brookhaven field, which was unsuccessful in finding the anticipated hydrocarbon trap projected based on 2-D seismic interpretation. Currently, we are conducting exploratory work on several seismic structures near existing production in Oklahoma and are negotiating the drilling rights on a number of prospects adjacent or on trend with our current properties. In the Mississippi properties, we are employing a combination of 2-D and 3-D seismic data to make detailed geologic interpretations of our existing properties on which we plan to continue to conduct in-field development drilling, and to assist in enhancing the installation and operation of secondary projects. PRINCIPAL AREAS OF ACTIVITY The following table sets forth, for our major producing areas, average net daily production of crude oil and natural gas on a BOE basis for each of the years in the three-year period ended December 31, 2000, and the number of productive wells producing at December 31, 2000. We sold our Louisiana properties on December 2, 1998.
Year Ended December 31 (a) At December 31, 2000 -------------------------------- -------------------- 1998 1999 2000 -------- -------- -------- Productive Wells -------------------------------------------- Percentage Gross Wells Net Wells of Net Average -------------------- -------------------- Wells Working BOE/Day BOE/Day BOE/Day Oil Gas Oil Gas Operated Interest -------- -------- -------- -------- -------- -------- -------- -------- -------- Mississippi 8,202 4,621 4,725 137 3 126 3 99% 95% Oklahoma 6,345 5,414 5,598 1,374 120 510 51 93% 41% Louisiana 2,452 -- -- -- -- -- -- -- -- Other 600 315 285 34 -- 15 -- 19% 49% -------- -------- -------- -------- -------- -------- -------- Total 17,599 10,350 10,608 1,545 123 651 54 ======== ======== ======== ======== ======== ======== ========
(a) In response to depressed crude oil prices during 1998 and early 1999, we significantly reduced minor and major repairs and drilling activity on our operated properties beginning in August 1998, ceased all repair work and 10 11 drilling activity in December 1998 and halted production on wells we determined to be uneconomical. We restarted repairs and maintenance on the properties we operate and began doing limited recompletion and workover activity in the second half of 1999. After we emerged from bankruptcy in April 2000, we initiated a capital expenditure program that commenced in June 2000 to return all remaining shut-in wells to production and to begin drilling and recompletion projects to increase production. MID-CONTINENT AREA In December 1997, we acquired interests in approximately 40,000 gross acres concentrated primarily in southern Oklahoma, including 12 principal producing fields. Of the 12 principal producing fields, we are the operator of ten fields. At December 31, 2000 we had an average working interest of approximately 75% in the ten fields we operate. These properties are very similar to our Mississippi salt basin operations because these properties will respond to very detailed study and exploitation to recover additional reserves not yet developed. In 2000, a total of 19 wells were drilled on the operated properties and one well was drilled on an outside operated property. A total of 17 gross wells were successfully completed as producing wells in 2000, including the outside operated well, and one well was completed as a water injection well. One dry hole was drilled in the Graham Deese field in an attempt to develop shallow gas deposits at approximately 1,600 feet. One of our 17 successfully completed wells was a shallow gas well drilled in the Graham Deese area with an initial flow rate of 180 Mcf per day. We own a 100% working interest in this well. The majority of the other drilling on our operated properties was directed at in-field development of proved undeveloped reserves primarily in the Tatums Unit, where we have a 49% working interest. In addition during 2000, we began interpreting 3-D seismic information, which had been acquired with the purchase of the Oklahoma properties, and have identified several drilling opportunities that we plan to commence early in 2001. Bumpass Field, Oklahoma. The Bumpass field, located in Carter County, Oklahoma, was discovered in 1924. Production is primarily from both structural and stratigraphic traps within the Deese and Springer reservoirs. The Deese reservoirs are typically encountered at depths between 3,500 and 4,500 feet with the Springer reservoirs located from 4,500 to 6,700 feet. We own an average working interest of approximately 64% in the Bumpass field. In 2000, our primary focus at Bumpass was to improve the operation of the existing Deese waterflood project by returning wells to production, which had not been repaired due to capital constraints in the prior year. In addition, based on detailed geologic interpretation of the field, it was found that several Springer completions drilled in 1998 and 1999 could be enhanced by implementing waterflood operations. In 2000, we initiated one new waterflood to recover additional reserves from these segmented reservoirs and currently plan to implement two additional waterflood projects for this purpose during 2001. Average net daily production in 2000 was 435 BOE compared to 451 BOE per day in 1999. Net proved reserves at December 31, 2000 totaled 4.0 MMBOE, a decrease of 11% from 4.5 MMBOE at the end of 1999. The decrease in reserves is primarily due to reserves produced during 2000 coupled with downward revisions in reserve estimates related to actual reservoir performance during 2000 in the Springer gas and Deese waterflood formations. East Fitts Field, Oklahoma. The East Fitts field was discovered in 1933 and is located in Pontotoc County, Oklahoma near the city of Ada. Production in the field is primarily from the Cromwell, Hunton and Viola reservoirs ranging in depth from 2,400 feet to 5,000 feet. Our average working interest in the East Fitts field is approximately 82%. In late 2000, we found shallow gas potential at a depth of approximately 1,600 feet in this mature field and have initiated plans to begin testing this potential using idle or available existing wellbores in the unit. We plan to continue to recomplete idle wells to exploit this shallow gas potential since current product prices are attractive. Our current emphasis at East Fitts, in addition to our plan to pursue the shallow gas, is to undertake the infill drilling of the Viola reservoir. We believe this development drilling will not only increase existing production but will also allow us to reclassify proved undeveloped reserves to proved developed producing reserves. In 2000, we drilled the EFU #12-6 as part of a pilot program to more fully evaluate this concept. The EFU # 12-6 was completed with an initial gross production rate of 90 BOE per day, and was continuing to produce at this rate by the end of 2000. This well has been encouraging and has prompted us to plan additional drilling for the East Fitts unit in 2001. At year end 2000, we were waiting on an available drilling rig to begin drilling in the East Fitts unit. 11 12 Average net daily production in 2000 was 1,182 BOE as compared to an average net daily production in 1999 of 997 BOE, a 19% increase. Net proved reserves at December 31, 2000 totaled 23.1 MMBOE representing approximately 23% of our total proved reserves. Year end 2000 net proved reserves are down from the net proved reserves at December 31, 1999, which totaled 23.7 MMBOE. The change in reserves is primarily due to reserves produced during 2000 and downward revisions in reserve estimates related to increased operating costs based on actual costs incurred during 2000. East Velma Middle Block Field, Oklahoma. The East Velma Middle Block is located in Stephens County, Oklahoma and was discovered in 1949. The field has been a primary producer in the Sims and Humphreys formations. The field is characterized as a steeply dipping structure with a large trapping fault. Our average working interest in this field is 63%. In 2000, we initiated plans to waterflood both of the producing formations based on offset performance in other segments of the field, which are outside operated. East Velma Middle Block is the only remaining block along this structural complex, which has not been enhanced through secondary recovery efforts. The majority of the work during 2000 has been to utilize existing wellbores for conversion to water injection wells. In 2000, we started the initial water injection in two wells and have seen early response in one of the offset producers within a two-month period. These encouraging results have led us to accelerate the planned installation of the waterflood facilities. This program was ongoing as of year end 2000 and is continuing into 2001. Proved net reserves totaled 11.6 MMBOE as of December 31, 2000, representing approximately 12% of our total proved reserves, as compared to proved net reserves of 11.8 MMBOE at year end 1999. Daily average net production from the East Middle Block field in 2000 averaged 516 BOE down from the 607 BOE per day experienced in 1999. Production from this field in 2000 was not significantly affected by the initiation of the waterflood activity due to the recent time frame in which this activity was started. Sholem Alechem Fault Block "A" Field, Oklahoma. The Sholem Alechem Fault Block "A" field is located in Stephens County, Oklahoma and was discovered in 1947. As with the Bumpass field, the production at Sholem Alechem originates primarily from the Deese and Springer reservoirs. We own an average working interest in the field of approximately 87%. In 2000, the main focus of work in Sholem Alechem was the continued repair of wells which had been left down due to capital constraints in 1999, and to increase the operating efficiency of the unit. We also deepened the Taylor #6 well to test the Goodwin section of the Basal Springer sand. We successfully completed this gas well with an initial gross flow rate of 640 Mcf per day (278 Mcf per day net). In addition, we continued to look for inactive well bores that could be deepened to test the Goodwin and Flattop sections of the Springer formation where several successful deepenings were done in 1998 and 1999. The scarcity of suitable or available wellbores for this purpose has resulted in our attempting to trade or purchase wellbores from other operators in the area to use to perform recompletions. In 2000, we were successful in arranging to trade for three wellbores, which we plan to utilize to exploit deeper gas reserve potential in 2001. Net daily production in 2000 from the Sholem Alechem field was 728 BOE, representing a 3% increase from the 705 BOE average in 1999. Net proved reserves at December 31, 2000 totaled 6.6 MMBOE, representing a decline of 6% from year end 1999 primarily due to reserves produced during 2000 and downward revisions in reserve estimates related to increased operating costs based on actual costs incurred during 2000. Tatums Field, Oklahoma. The Tatums field is located in Carter County, Oklahoma and was discovered in 1927. The field is primarily a Deese sand structure between the average depths of 2,500 and 3000 feet. Our average working interest in the Tatums field is 49%. During 2000, we reprocessed our 3-D seismic in the Tatums field, and were able to discern that the field was made up of a number of flow channels primarily on the west side of the field, which had not been previously recognized. We began an in-field development drilling program as a pilot project to further develop the reserves believed to lie in these areas, in a portion of the field that was not as densely developed as the east and southeast portions. As of December 31, 2000, we had drilled a total of eleven wells and were encouraged with the amount of undrained pay sands that were encountered. We now plan to augment the existing waterflood program to increase water injection into these areas to enhance the recovery of these remaining reserves. Net daily production from the Tatums field in 2000 averaged 597 BOE per day, representing an increase of 12%, as compared to average net daily production of 534 BOE in 1999. The net daily production figures for 2000 do not reflect any benefit from the planned increased water injection into this new pilot area. Total net proved reserves as of December 12 13 31, 2000 were 3.5 MMBOE, an increase of 7% from the total net proved reserves as of December 31, 1999 of 3.3 MMBOE, due to the development drilling program. Other Oklahoma. We operate five other fields in Oklahoma: o Cox Penn; o Eola; o Graham Deese; o Jennings Deese; and o North Alma Deese As discussed under "Secondary Recovery", we launched pilot waterflood projects in the North Alma Deese, Jennings Deese and Graham Deese units during 2000. Continued development of these waterflood projects is included in our 2001 capital expenditure program. Total average net daily production in 2000 from these fields was 1,167 BOE as compared to average net daily production of 1,028 BOE in 1999. At December 31, 2000, net proved reserves in these fields were approximately 17.4 MMBOE. Net proved reserves in these fields were 18.5 MMBOE at December 31, 1999. We also have working interests in three other producing properties in Oklahoma operated by others. At December 31, 2000, net proved reserves in these three fields were estimated at 2.7 MMBOE as compared to net reserves of 3.9 MMBOE at December 31, 1999. Net average daily production from these properties was 973 BOE in 2000 as compared to average net daily production of 1,041 BOE in 1999. GULF COAST AREA Brookhaven Field, Mississippi. The Brookhaven field is located in Lincoln County, Mississippi near the town of Brookhaven. The field was discovered in 1943 and covers a surface area of approximately 13,000 acres. We acquired the Brookhaven field in 1995 and currently own an average working interest of 98% in the field. The field has had approximately 200 wells drilled on the structure to various depths. Productive intervals in the field range from the Tuscaloosa formation at approximately 10,500 feet to the Hosston formation at 16,700 feet. The Tuscaloosa formation was the primary reservoir that was developed in the field, until we added the Washita Fredicksburg, Paluxy and Rodessa formations through deeper exploratory drilling. In 2000, we drilled two wells to further develop and extend the productive limits of the Washita Fredicksburg and Paluxy formations using reprocessed seismic data. As mentioned previously, one of the wells was an unsuccessful exploratory well that was drilled to test an untested fault block on the east flank of the field. The second well was a successful development well in the Washita Fredicksburg formation with a pumping rate of 288 BOE gross per day or 205 BOE net at completion. At the end of 2000, we were in the process of installing a new secondary recovery project on the west side of the field to recover remaining reserves from a Tuscaloosa reservoir, which has not been waterflooded. This project is ongoing and is expected to be completed in the first quarter of 2001, when water injection will be initiated. Production in Brookhaven in 2000, averaged 514 BOE net per day and net proved reserves at December 31, 2000 were 5.2 MMBOE. Daily production was 8% lower than 1999 levels due to natural production decline. Reserves were 19% below 1999 as a result of reserves produced during 2000 in addition to downward revisions in reserves. Reserves were revised downward due to re-interpretation of the aerial extent of one of the productive intervals, actual reservoir performance during 2000 and increased operating costs associated with returning wells to production in 2000. Additional development drilling and the expansion of waterflood projects are planned for 2001. Laurel Field, Mississippi. The Laurel field is located in Jones County, Mississippi and lies predominantly within Laurel city limits. We acquired our initial interest in this field in 1983 and currently own an average working interest of 95% in the field. The field is a multi-pay geologic setting with producing horizons from the Eutaw formation at approximately 7,500 feet to the Hosston formation at approximately 13,500 feet. It is our largest oil producing property and represents approximately 46% of our total Mississippi production on a BOE basis in 2000. At December 31, 2000, the 13 14 field contained 42 gross wells producing from the Stanley, Christmas, Tuscaloosa, Washita Fredicksburg, Paluxy, Mooringsport, Rodessa, Sligo and Hosston reservoirs. We employed 3-D seismic technology to assist in defining the multi-pay zones in the field and performed an extensive drilling program to increase primary production, using a combination of vertical, high-angle and horizontal drilling techniques. The average net daily production in 2000 from Laurel was 2,210 BOE, down 4% from 1999 levels. At December 31, 2000, net proved reserves were 9.9 MMBOE, down approximately 21% from year end 1999. The decrease in reserves is attributable to reserves produced during 2000 coupled with downward revisions in reserve estimates. The downward revisions in reserve estimates relate to actual reservoir performance during 2000, re-mapping of productive limits within several fault blocks and increased operating costs based on actual costs incurred during 2000. We have identified additional development locations within the Laurel Field, and plan to initiate some additional development drilling on these projects in 2001. In addition, we have also mapped several untested fault traps on the west side of the Laurel field structure, which we are evaluating for either drilling or negotiating farm-out arrangements, depending on the risk assessment. Martinville Field, Mississippi. The Martinville Field is located in Simpson County, Mississippi. We acquired our initial interest in the Martinville field in 1989 and currently own an average working interest of 99% in the field. The field covers more than 7,400 acres and currently has 19 gross producing wells. The Martinville field is similar to the Laurel field, in the respect that it is geologically complex with multiple horizons. The field consists of numerous producing formations from approximately 8,500 feet in the Washita Fredicksburg formation to the Cotton Valley formation at approximately 14,500 feet. The field has identified reserves in the Mooringsport, Rodessa, Sligo and Hosston formations as well as the Washita Fredicksburg and Cotton Valley formations. In 2000, we drilled one development well that was completed as a producing oil well in July and drilled a second well that was still drilling at year end. Both of these wells were drilled to further develop the 8,500 feet Washita Fredicksburg formation. This drilling program was delayed in 2000 due to the need to re-interpret portions of our 3-D seismic survey and the unavailability of drilling rigs due to the surge of drilling activity in the industry towards the end of 2000. We plan to continue this development drilling program in 2001 and to concentrate on improving the monitoring of waterflood response to maximize secondary recoveries in the field. Net proved reserves at year end 2000 totaled 4.0 MMBOE, a 25% decrease from year end 1999. The decrease in net reserves is primarily due to reserves produced during 2000, downward revisions in reserve estimates attributable to actual reservoir performance during 2000 and increased operating costs based on actual costs incurred during 2000. Production in 2000 averaged a daily net rate of 647 BOE, which was a 17% decline from production levels in 1999. The primary decline in average daily net production in 2000 as compared to 1999 was due to the production declines on the MFU 14-13#1 well from peak production rates of approximately 500 BOPD in 1999 down to 200 BOPD by the third quarter of 2000. Soso Field, Mississippi. The Soso Field is located in Smith and Jones Counties, Mississippi and covers approximately 6,500 acres. We acquired our initial interest in this field in 1990 and currently own an average working interest of 94% in the field. Since 1997, we have initiated secondary recovery projects in the Cotton Valley, Sligo and Rodessa formations. We directed our efforts in 2000 toward improving the secondary recovery efficiency by increasing water injection rates and re-activating shut-in wells associated with improving this project. In 2000, the average daily net production was 486 BOE, an increase of 37% from the 1999 average daily net production of 354 BOE. In 1998, we acquired 35 miles of new 2-D seismic data across the Soso field. This 2-D seismic data has enhanced our interpretation of the geologic structures of the Soso field and led to the commitment to drill two additional development wells for the Cotton Valley formation. We began drilling one of these wells in December 2000 which was completed in February 2001. The second well was spud in February 2001 and is still drilling. Net proved reserves as of December 31, 2000 in the Soso field were 5.1 MMBOE, representing an 8% decrease from net proved reserves at year end 1999, primarily due to reserves produced during 2000 and downward revisions in reserve estimates related to increased operating costs based on actual costs incurred during 2000. Summerland Field, Mississippi. The Summerland field is located in Jones and Covington Counties, Mississippi and covers approximately 1,300 acres. We acquired operating control of the Summerland field in 1989 and currently own an 14 15 average working interest of 90%. The productive structure of the field is a broad, elongated, fault-bounded anticline with productive intervals from the Tuscaloosa formation at approximately 6,000 feet to the Mooringsport formation at 12,500 feet. At December 31, 2000, we operated 21 gross producing wells. In 2000, we directed our operations primarily to returning wells to production and improving lift efficiency on the producing wells. In addition, several projects were completed to assist in the disposal of water produced from this field, to ease production restrictions caused by produced water in past operations. Average daily net production for 2000 was 714 BOE, or an increase of 45% over average daily net production of 494 BOE for 1999. At December 31, 2000, the Summerland field had proved reserves of 4.0 MMBOE, a decrease of approximately 29% from year end 1999. This decrease was primarily due to reserves produced during 2000 and downward revisions in reserve estimates related to increased operating costs based on actual costs incurred during 2000. OTHER DOMESTIC PROPERTIES We also have working interests in other producing properties in Mississippi and Texas. We operate the Bentonia and Cranfield fields in Mississippi. We own non-operated working interests in the Glazier field in Mississippi, the Clarksville field in Texas and a field in Federal waters offshore North Padre Island, Texas. As of December 31, 2000, these fields had combined net proved reserves of 3.6 MMBOE. Aggregate average daily net production from these properties for both 1999 and 2000 was approximately 430 BOE. In addition, we have leasehold and production in approximately 2,700 gross acres in Navarro County, Texas, which currently produces from the Cotton Valley formation. In 2001, we intend to explore the Bossier sand development for potential natural gas production on our acreage in Texas by acquiring farm-outs to these shallow rights and utilizing our existing wells to test the productive potential. TUNISIAN OPERATIONS We have decided to discontinue our participation in the exploration of two Tunisia, North Africa permits due to capital commitments in excess of $7 million, net to our interest, during 2001, including cash calls currently due totaling $753,000 for January and February on the Anaguid permit. We own a 45.8% interest in the Anaguid permit operated by Anadarko Tunisia Anaguid Company and a 12.5% interest in the Fejaj permit operated by Bligh Tunisia, Inc. We have been seeking buyers for our interests in these two permits since emerging from bankruptcy in March 2000 but have not yet been successful in selling these interests. We believe it is in our best interest to preserve our ownership in these permits under the protection of the bankruptcy court while we attempt to negotiate sales of our interests in the permits to a third party or parties and to reach settlements with respect to our obligations under the permits. Therefore, our two subsidiaries that own these permits, Coho Anaguid, Inc. and Coho International Limited, filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001. We anticipate that the other interest owners in these Tunisian permits will claim that these two subsidiaries are obligated for their share of the 2001 capital commitments totaling in excess of $7 million under the terms of the related operating and permit agreements. PRODUCTION The following table contains information regarding our production volumes, average prices received and average production costs associated with our sales of crude oil and natural gas for each of the years in the three-year period ended December 31, 2000:
Year Ended December 31, ----------------------------------- 1998 1999 2000 --------- --------- --------- CRUDE OIL: Volumes (MBbls) ................................ 5,069 3,343 3,535 Average sales price (per Bbl)(a) ............... $ 10.40 $ 15.40 $ 23.31 NATURAL GAS: Volumes (MMcf) (b) ............................. 8,124 2,608 2,087 Average sales price (per Mcf)(c) ............... $ 1.98 $ 2.24 $ 3.73 AVERAGE PRODUCTION COST (per BOE)(d) ............. $ 4.18 $ 5.60 $ 7.55
15 16 (a) Includes the effects of crude oil price hedging contracts. Price per Bbl before the effect of hedging was $10.40 for the year ended December 31, 1998, $15.40 for the year ended December 31, 1999 and $26.10 for the year ended December 31, 2000. (b) Natural gas production in 1998 includes production from the Louisiana properties that were sold on December 2, 1998. (c) Includes the effects of natural gas price hedging contracts. Price per Mcf before the effect of hedging was $1.92 for the year ended December 31, 1998, $2.24 for the year ended December 31, 1999 and $3.99 for the year ended December 31, 2000. (d) Includes lease operating expenses and production taxes. Average production costs per BOE increased from 1999 to 2000 primarily due to increases in production taxes, fluid production, utility costs, costs for well services and materials. See "Management's Discussion and Analysis-Results of Operations" for a more detailed discussion. DRILLING ACTIVITIES During the periods indicated, we drilled or participated in the drilling of the following wells:
Year Ended December 31, -------------------------------------------------- 1998 1999 2000 -------------- -------------- -------------- Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- EXPLORATORY: Crude Oil ...................................... 1 1.0 -- -- -- -- Dry holes (a) .................................. 2 2.0 1 0.5 1 1.0 DEVELOPMENT: (b) Crude oil ...................................... 26 21.7 -- -- 16 10.8 Natural gas .................................... 8 6.5 3 3.0 3 1.5 Dry holes ...................................... 5 4.9 2 1.5 2 2.0 Service wells .................................. 2 1.0 -- -- 1 0.5 ----- ----- ----- ----- ----- ----- Total ....................................... 44 37.1 6 5.0 23 15.8 ===== ===== ===== ===== ===== =====
(a) 1999 well was drilled in Tunisia, North Africa. (b) Included in drilling activities are wells deepened to a lower reservoir through existing well bores. In 1999, all wells under "Development" were deepenings within existing well bores. At December 31, 2000, we were drilling five gross wells, including two gross wells (1.9 net wells) in Mississippi and three gross wells (2.0 net wells) in Oklahoma. RESERVES The following table summarizes our net proved crude oil and natural gas reserves as of December 31, 2000, which have been reviewed by Ryder Scott Company with regard to our Mississippi properties and Sproule Associates, Inc. with regard to our Oklahoma properties. The other properties in the table are related to our crude oil and natural gas reserves located in Texas which have been audited, depending on location, by the independent engineers named in the preceding sentence. 16 17
AS OF DECEMBER 31, 2000 ------------------------------------------------------------ CRUDE NATURAL NET PROVED PRESENT VALUE OIL GAS RESERVES OF PROVED (MBBLS) (MMCF) (MBOE) RESERVES ------------ ------------ ------------ ------------ (IN THOUSANDS) OKLAHOMA PROPERTIES: Bumpass 2,975 6,326 4,029 $ 46,118 Cox Penn 3,145 0 3,145 24,268 East Fitts 23,036 449 23,111 130,192 East Velma Middle Block 10,920 4,087 11,601 92,696 Eola 2,247 2,797 2,713 34,887 North Alma Deese 8,869 0 8,869 49,932 Sholem Alechem 6,011 3,552 6,603 54,249 Tatums 3,530 5 3,531 27,752 Other Oklahoma - operated 2,630 147 2,655 12,424 Other Oklahoma - non-operated 1,919 4,964 2,745 39,382 ------------ ------------ ------------ ------------ Total Oklahoma Properties 65,282 22,327 69,002 511,900 ------------ ------------ ------------ ------------ MISSISSIPPI PROPERTIES: Brookhaven 5,126 334 5,184 51,239 Laurel 9,892 0 9,892 57,580 Martinville 3,984 199 4,017 28,743 Soso 5,049 578 5,145 34,550 Summerland 3,979 0 3,979 22,404 Other Mississippi 1,396 2,550 1,820 25,296 ------------ ------------ ------------ ------------ Total Mississippi Properties 29,426 3,661 30,037 219,812 ------------ ------------ ------------ ------------ Other Texas Properties 1,285 2,723 1,739 24,889 ------------ ------------ ------------ ------------ TOTAL 95,993 28,711 100,778 $ 756,601 ============ ============ ============ ============
At December 31, 2000, we had net proved developed reserves of 69,928 MBOE and net proved undeveloped reserves of 30,850 MBOE. The present value of proved reserves of $756.6 million represented $520.9 million for the proved developed reserves and $235.7 million for the proved undeveloped reserves. The present value of proved reserves is based on year end market prices of $26.80 per barrel for crude oil and $9.78 per MMbtu for natural gas. Market prices for crude oil and natural gas have fluctuated significantly over the last three years. These year end market prices are high in comparison to historical average crude oil and natural gas prices in the most recent three-year period. At December 31, 1999, we reported total proved reserves of 113,886 MBOE, and the present value of proved reserves was $790.2 million. Reserves declined from 1999 to 2000 due to reserves produced during 2000 and due to downward revisions in reserve estimates as set forth below. Reserve estimates for the following properties are no longer included in proved reserves because: o We have no further plans to participate in future drilling on undeveloped acreage in the North Padre Island field located in Federal waters, offshore Texas. Therefore, the net 879 MMcf of natural gas reserves associated with this proved undeveloped drilling project has been removed. o Our new management team believes that the characteristics associated with the Smackover formation in our East Texas field do not currently warrant drilling for the deeper undeveloped reserves in the Smackover formation in this field. The Smackover has historically tested sour gas, which requires gas processing and special transportation arrangements for marketing the gas and associated liquids. Proved net reserves of 1.5 MMBOE, associated with two proved undeveloped drilling projects, have been removed at year end 2000. o Our new management has reviewed the recent horizontal drilling results in the Summerland Field, targeting thin, strong waterdrive, heavy oil productive sands. Because of the risk associated with continuing a program to horizontally drill wells in these types of reservoir sands for improved recoveries we will not actively pursue this project. Proved net reserves of 1.2 MMBOE, associated with three drilling projects on undeveloped acreage, have been removed at year end 2000. 17 18 The remaining changes to our net proved reserve base have been a function of reservoir performance and an increase in operating expenses during the year. Operating costs have increased during the year 2000 due to increased fluid production, utility costs, costs for well services and materials. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves, including many factors beyond our control. The estimates of the reserve engineers are based on several assumptions, including the following: o future production; o revenues; o taxes; o production costs; o success of development drilling; o development expenditures; and o quantities of recoverable crude oil and natural gas reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth herein. In addition, our reserves might be subject to revision based upon: o actual production performance; o results of future development; o prevailing crude oil and natural gas prices; and o other factors. In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted. Except to the extent we acquire additional properties or additional interests in existing properties containing proved reserves or conduct successful exploration and development activities associated with our proven and unproven reserves, or both, our proved reserves will decline as reserves are produced. Future crude oil and natural gas production is therefore highly capital intensive and dependent upon the level of success in acquiring or finding additional reserves. For further information on reserves, costs relating to crude oil and natural gas activities and results in operations from producing activities, see "Supplementary Information Related to Oil and Gas Activities" appearing in Note 14 to our consolidated financial statements included in this Form 10-K. ACREAGE The following table summarizes the developed and undeveloped acreage we owned or leased at December 31, 2000:
Developed Undeveloped ---------------- ---------------- Gross Net Gross Net ------ ------ ------ ------ Mississippi ...................................... 24,246 22,989 21,315 15,907 Oklahoma ......................................... 38,463 29,218 60 60 Texas ............................................ 4,860 3,678 1,196 1,119 Offshore Gulf of Mexico .......................... 5,760 2,269 -- -- ------ ------ ------ ------ Total .................................. 73,329 58,154 22,571 17,086 ====== ====== ====== ======
18 19 At December 31, 2000, we also held a 45.8% working interest in an exploratory permit in Tunisia, North Africa, covering approximately 1,130,000 gross acres. TITLE TO PROPERTIES As is customary in the oil and gas industry, in many circumstances, we make only a limited review of title to undeveloped crude oil and natural gas leases at the time we acquire them. However, before we acquire developed crude oil and natural gas properties, and before drilling commences on any leases, we cause a thorough title search to be conducted, and any material defects in title are remedied to the extent possible. To the extent title opinions or other investigations reflect title defects, we, rather than the seller of the undeveloped property, are typically obligated to cure any title defects at our expense. We could lose our entire investment in any property we drill, if we have a title defect of a nature that we could not remedy or cure. We believe that we have good title to our crude oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. The crude oil and natural gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties. COMPETITION The crude oil and natural gas industry is highly competitive. We encounter strong competition from major oil companies and independent operators in acquiring properties and leases for the exploration for, and production of, crude oil and natural gas. Competition is particularly intense with respect to the acquisition of desirable undeveloped crude oil and natural gas properties. The principal competitive factors in the acquisition of desirable undeveloped crude oil and natural gas properties include the staff and data necessary to identify, investigate and purchase these properties, and the financial resources necessary to acquire and develop these properties. Many of our competitors have financial resources, staff and facilities substantially greater than ours. In addition, the producing, processing and marketing of crude oil and natural gas is affected by a number of factors which are beyond our control, the effect of which cannot be accurately predicted. The principal resources necessary for the exploration and production of crude oil and natural gas are: o leasehold prospects under which crude oil and natural gas reserves may be discovered; o drilling rigs and related equipment to explore for these reserves; and o knowledgeable personnel to conduct all phases of crude oil and natural gas operations. We compete for these resources with both major crude oil and natural gas companies and independent operators. Although we believe our current operating and financial resources will be adequate to preclude any significant disruption of our operations in the immediate future, the continued availability of these materials and resources to us cannot be assured. CUSTOMERS AND MARKETS Substantially all of our crude oil is sold at the wellhead at posted prices, as is customary in the industry. In some circumstances, natural gas liquids are removed from our natural gas production and are sold by us at posted prices. During 2000, EOTT Energy Operating Limited Partnership accounted for 41% of our revenues and Amoco Production Company accounted for 29% of our revenues. In October 2000, we began selling our crude oil that had been previously sold to Amoco to TEPPCO Crude Oil, L.P. and Sunoco, Inc. While we believe our relationships with EOTT, TEPPCO and Sunoco have been and will continue to be good, any loss of revenue from these customers due to nonpayment by the customer would have an adverse effect on our net income and earnings per share on our income statement and, ultimately, may affect our share price. In addition, any significant late payment may adversely affect our short term liquidity position. Effective November 1, 2000, we entered into a 14-month crude oil purchase agreement with EOTT. Under this crude oil purchase agreement, we committed the majority of our crude oil production in Mississippi to EOTT through December 31, 2001 on a pricing basis of posting plus a premium with adjustment made for gravity. 19 20 Additionally, we continue to sell EOTT approximately 50% of our heavy Mississippi crude oil under a separate contract that is renewable on an annual basis with similar pricing arrangements based on postings plus a premium with an adjustment for gravity. This contract also sets a minimum well head price of $8.50 per barrel for this heavy crude oil. The majority of crude oil production in Oklahoma is sold to TEPPCO Crude Oil, L.P. and Sunoco, Inc. on a NYMEX pricing basis minus a discount with an additional discount for fluctuations in the price for our sour oil. Our contracts with Teppco and Sunoco expire on September 30, 2001. Pursuant to the Amoco purchase and sale agreement entered into in November 1997, Amoco has retained a right of first refusal to match, in all respects, a competitive bid for the purchase on an annual basis of our crude oil through 2007. The sales prices we receive for crude oil and natural gas may vary significantly during the year due to the volatility of the crude oil and natural gas market, particularly during the cold winter and hot summer months. As a result, we periodically enter into forward sale agreements or other arrangements for a portion of our crude oil and natural gas production to hedge our exposure to price fluctuations. Gains and losses on these forward sale agreements are reflected in crude oil and natural gas revenues at the time of sale of the related hedged production. While intended to reduce the effects of the volatility of the prices received for crude oil and natural gas, these hedging transactions may limit our potential gains if crude oil and natural gas prices were to rise substantially over the price established by the hedge. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Hedging Activities and Other Derivatives" and note 1 to our consolidated financial statements for more information related to hedging. OFFICE AND FIELD FACILITIES We currently lease 26,751 square feet for our executive and administrative offices in Dallas, Texas, under a lease that continues through December 2005. We lease field offices in Laurel, Mississippi, covering approximately 5,000 square feet under a month-to-month lease. We are currently evaluating the Laurel lease as well as other alternatives. We also lease office space in Ratliff City, Oklahoma, covering approximately 10,000 square feet through January 2003. GOVERNMENTAL REGULATION Crude oil and natural gas exploration, development and production are subject to various types of regulation by local, state and federal agencies. These laws and regulations govern, among other things: o issuing permits and bonds in connection with drilling activities; o imposing a production severance tax; o regulating operations on secondary recovery projects; o regulating the location of wells; o regulating the method of drilling and casing wells; o regulating the surface use and restoration of properties upon which wells are drilled; and o regulating the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations in which our properties are located, including those of Mississippi, Oklahoma and Texas. These laws and regulations include the regulation of: o the size of drilling and spacing units or proration units; o the density of wells that may be drilled; o unitization or pooling of crude oil and natural gas properties; 20 21 o maximum rates of production from crude oil and natural gas wells; o restrictions on the venting or flaring of natural gas; and o requirements regarding the ratability of production. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of land and leases. The effect of these regulations is to limit the amount of crude oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the crude oil and natural gas industry increases our cost of doing business and effects our profitability. Because such rules and regulations are constantly amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Each state generally imposes a production or severance tax with respect to production and sale of crude oil, natural gas and natural gas liquids within their respective jurisdictions. For the most part, state production taxes are applied as a percentage of production or sales. Currently, we are subject to production tax rates of up to 6.2% in Mississippi and 7.2% in Oklahoma. Some of our operations are conducted on federal and Indian oil and gas leases that are subject to a variety of regulations and rules published by the United States Minerals Management Service and other federal agencies. For offshore leasing operations, the Minerals Service issues detailed regulations and orders which govern, among other things: o the approval for exploration, development and production plans; o the issuance of permits for drilling operations and drilling bonds; o the engineering and construction specifications for offshore production facilities; and o the plugging and abandonment of such wells. With respect to gas royalty valuation, the Minerals Service has published final rules that amend regulations governing valuation for royalty purposes of gas produced from federal and Indian leases. The Minerals Service has also published proposed rules to amend the current federal crude oil royalty valuation regulations and the current Indian crude oil royalty valuation regulations. With regards to the proposed rules, we cannot predict what action the Minerals Service might take on these matters, nor can we predict at this stage of the rulemaking proceedings how we might be affected by amendments to these regulations. With regards to the other regulations and amendments thereto, management believes that these regulations and amendments to the regulations have not had a material adverse effect on our results of operations. The Federal Energy Regulatory Commission, in response to the Energy Policy Act of 1992, has implemented regulations establishing an indexing system for transportation rates for crude oil pipelines. The regulations would generally index transportation rates to inflation. These regulations may affect the price that we receive from the sale of crude oil due to a possible increase in the cost of transporting oil to market. We are not able to predict with certainty what effect, if any, these regulations will have on us, but other factors being equal, the regulations may tend to increase transportation costs or reduce wellhead prices for these commodities. The ultimate impact on us of these complex and overlapping rules and regulations, many of which are repeatedly subjected to judicial challenge and interpretation, cannot be predicted. ENVIRONMENTAL REGULATIONS Our oil and gas operations and properties are subject to numerous federal, state and local laws and regulations relating to environmental protection. These laws and regulations may: o require us to obtain permits before drilling; 21 22 o restrict the types, quantities and concentration of various substances that can be released into the environment through drilling and production activities; o limit or prohibit drilling activities on some lands lying within wilderness, wildlife refuges or preserves, wetlands and other protected areas; o restrict the discharge of produced waters and other oil and gas wastes into navigable waters; o regulate the treatment, storage and disposal of hazardous waters; and o regulate the remediation of contaminated sites. In addition, these laws and regulations may impose substantial liabilities for our failure to comply with them or for any contamination resulting from our operations. We maintain insurance against losses or liabilities arising from our operations in accordance with customary industry practices and in amounts we believe reasonable. However, insurance is often not available against all operational risks or is not economically feasible for us to obtain. If a significant event occurs that imposes liability on us that is either not insured or not fully insured, a material adverse effect on our financial condition and results of operations could result. We take the issue of environmental responsibility very seriously and work diligently to comply with applicable federal, state and local environmental rules and regulations including but not limited to, the Oil Pollution Act of 1990, the Federal Water Pollution Control Act of 1972, the Comprehensive Environmental Response, Compensation, and Liability Act, the Resource Conservation and Recovery Act. Management believes compliance with such laws and regulations has not had a material adverse effect on our operations or financial condition in the past. To date, compliance with such laws and regulations has not materially affected our operations or financial condition. However, because environmental laws and regulations are becoming increasingly more stringent, there can be no assurances that such laws and regulations or any environmental law or regulation enacted in the future will not significantly affect our operations or financial condition. A significant portion of our operations in Mississippi is conducted within city limits. Each year we are required to meet tests of financial responsibility to obtain permits to conduct new drilling operations. We are conducting a voluntary program to remove inactive aboveground storage tanks from our well sites and to replace them, as necessary, with newer aboveground storage tanks. Some states have enacted statutes governing the handling, treatment, storage and disposal of waste containing naturally occurring radioactive material. Naturally occurring radioactive material is present in varying concentrations in subsurface and hydrocarbon reservoirs around the world and may be concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Mississippi legislation prohibits the transfer of property for residential or other unrestricted use if the property evidences concentrations of naturally occurring radioactive material above prescribed levels because of crude oil and natural gas production activities. We are voluntarily remediating naturally occurring radioactive material concentrations identified at several fields in Mississippi. EMPLOYEES At March 1, 2001, we had 98 employees associated with our operations, including 21 field personnel in Mississippi and 27 field personnel in Oklahoma. None of our employees is represented by a union. We consider our employee relations to be satisfactory. ITEM 3. LEGAL PROCEEDINGS Hicks Muse Lawsuits. We are the plaintiff in a lawsuit styled Coho Energy, Inc. v. Hicks, Muse, et al, which we filed in the District Court of Dallas County, Texas, 68th Judicial District filed on May 27, 1999. This lawsuit has been removed to the United States Bankruptcy Court for the Northern District of Texas, Dallas Division, where it currently is pending. The lawsuit alleges: 22 23 o breach of the written contract terminated by HM4 Coho L.P., a limited partnership formed by Hicks Muse on behalf of the Hicks, Muse, Tate & Furst Equity Fund IV, in December 1998; o breach of the oral agreements reached with HM4 on the restructured transaction in February 1999; and o promissory estoppel. In the lawsuit, we have sought monetary damages of approximately $300 million. Discovery is substantially complete and both sides have filed motions for summary judgement, which were heard during January 2001. The Court has now ruled on the motions. The Court has denied our motion for summary judgment, and has granted, in part, and denied, in part, Hicks, Muse's motion. Based on these orders, it appears that we will be able to go to trial on a claim for breach of contract that has an actual damages of up to $165 million. This description is only a general description of the Hicks Muse lawsuit and should not be relied on as conclusively stating all the alleged facts, claims or circumstances surrounding the lawsuit. We are not able to evaluate the recovery we might receive in the lawsuit. Additionally, our old shareholders are eligible to receive 20% of any proceeds available from this lawsuit after fees and expenses pursuant to our plan of reorganization. On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of Hicks, Muse, Tate & Furst, filed a lawsuit in the United States District Court of for the Northern District of Texas, Dallas Division against certain of our former officers alleging, among other things, such officers made or caused to be made false and misleading statements as to the proved oil and gas reserves purportedly owned by us. The plaintiffs are asking for compensatory damages of approximately $15 million plus punitive damages. Pursuant to our bylaws, we may be required to indemnify such former officers against damages incurred by them as a result of the lawsuit not otherwise covered by our directors' and officers' liability insurance policy. The judge has dismissed certain claims and the case is set for trial in the spring of 2002. We believe the lawsuit is without merit and do not expect the outcome of the lawsuit to have a material adverse effect on our financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 23 24 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our common stock was, until June 7, 1999, listed on the Nasdaq Stock Market under the symbol "COHO." Our common stock is currently traded on the Nasdaq's OTC Bulletin Board under the symbol "CHOH." The following table shows the high and low sale prices of our common stock over recent periods.
HIGH LOW ---- --- 1999 1st Quarter $ 3 1/8 $ 1/2 2nd Quarter 1 1/32 3rd Quarter 1 5/8 7/32 4th Quarter 3/4 5/32 2000 1st Quarter $ 3/4 $ 1/5 2nd Quarter 12 2 3rd Quarter 8 1/4 6 4th Quarter 6 3/4 2 7/8
As a result of our financial condition and decreases in the market value of our common stock during 1999, the Nasdaq Stock Market on March 8, 1999, suspended trading of our common stock. As of the close of business on June 4, 1999, our common stock was delisted from Nasdaq. As a result of these actions, our common stock is not currently listed but is trading over the counter. At December 31, 2000, there were 191 holders of record of our common stock. We believe we have approximately 5,523 beneficial holders of our common stock. Prior to March 31, 2000, the effective date of the plan of reorganization, we had 25,603,512 shares of old common stock issued and outstanding. Old shareholders received shares of new common stock on a basis of one share of new common stock for 40 shares of old common stock on the effective date. We have never paid cash dividends on our existing common stock and we do not intend to pay cash dividends on our new common stock. Because Coho Energy, Inc. is a holding company, our ability to pay dividends depends on the ability of our subsidiaries to pay cash dividends or make other cash distributions. Our debt agreements generally prohibit the subsidiaries from paying dividends or making cash distributions. Our board of directors has sole discretion over the declaration and payment of future dividends. Any future dividends will depend on: o profitability; o financial condition; o cash requirements; o future prospects; o general business conditions; o the terms of our debt agreements; and o other factors our board of directors believes relevant. 24 25 ITEM 6. SELECTED FINANCIAL DATA The following selected consolidated financial data for each of the five years in the period ended December 31, 2000 are derived from, and qualified by reference to, our audited consolidated financial statements included in Item 8 of this Form 10-K. The information presented below should be read in conjunction with our consolidated financial statements and the related notes and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" included in this Form 10-K. The selected consolidated financial data presented below is not necessarily indicative of the future results of our operations or financial performance.
YEARS ENDED DECEMBER 31, ---------------------------------------------------------------- 1996 1997 1998 1999 2000 --------- --------- --------- --------- --------- (IN THOUSANDS, EXCEPT EARNINGS PER SHARE AMOUNTS) STATEMENT OF EARNINGS DATA: Operating revenues .................................... $ 54,272 $ 63,130 $ 68,759 $ 57,323 $ 90,182 Operating costs ....................................... 13,875 15,970 26,859 21,155 29,320 General and administrative expenses ................... 7,264 7,163 7,750 9,905 7,137 Reorganization costs .................................. -- -- -- 3,123 12,004 Allowance for bad debt ................................ -- -- 894 -- 765 Depletion and depreciation ............................ 16,280 19,214 28,135 13,702 15,316 Writedown of crude oil and natural gas properties ...................................... -- -- 188,000 5,433 3,027 Net interest expense (a) .............................. 7,464 10,474 32,721 33,698 50,907 Other expense ......................................... -- -- 3,023 1,048 -- Income tax expense (benefit) .......................... 3,483 4,021 (14,383) (26) -- Net earnings (loss) before extraordinary items ........ 5,906 6,288 (203,346) (30,715) (28,294) Net earnings (loss) ................................... 5,906 6,288 (203,346) (30,715) (32,722) Basic earnings (loss) before extraordinary items per common share(b) ....................... $ 11.71 $ 1.16 $ (317.68) $ (47.99) (1.98) Basic earnings (loss) per common share(b) ............. $ 11.71 $ 1.16 $ (317.68) $ (47.99) (2.29) Diluted earnings (loss) before extraordinary items per common share(c) ....................... $ 11.61 $ 1.13 $ (317.68) $ (47.99) (1.98) Diluted earnings (loss) per common share(c) ........... $ 11.61 $ 1.13 $ (317.68) $ (47.99) (2.29) OTHER FINANCIAL DATA: Capital expenditures .................................. $ 52,384 $ 72,667 $ 70,143 $ 6,349 $ 25,272 BALANCE SHEET DATA: Working capital (deficit)(d) .......................... $ 6,662 $ (2,021) $(388,297) $(407,490) $ (2,647) Net property and equipment ............................ 210,212 531,409 324,574 311,788 317,667 Total assets .......................................... 230,041 555,128 350,068 348,801 366,791 Long-term debt, excluding current portion ............. 122,777 369,924 -- -- 282,412 Total shareholders' equity ............................ 81,466 142,103 (61,243) (91,958) 61,509
(a) Amount for 2000 includes interest expense of $36,192 and interest expense related to embedded derivative of $15,163, partially offset by interest income of $448. (b) Basic per share amounts have been computed by dividing net earnings after preferred dividends by the weighted average number of shares outstanding: 504 in 1996; 542 in 1997; 640 in 1998; 640 in 1999; and 14,266 in 2000. (c) Diluted per share amounts have been computed by dividing net earnings after preferred dividends by the weighted average number of shares outstanding including common stock equivalents, consisting of stock options and warrants, when their effect is dilutive: 509 in 1996; 558 in 1997; 640 in 1998; 640 in 1999; and 14,266 in 2000. (d) Amounts for 1998 and 1999 include $384,031 and $388,685, respectively, related to the current portion of long-term debt. The working capital deficit as of December 31, 1999 also includes liabilities subject to compromise as a result of the bankruptcy filing. 25 26 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with our consolidated financial statements included in this Form 10-K. Some information contained in this Form 10-K, including information with respect to our plans and strategy for our business, are forward-looking statements. For more information about the limitations associated with these types of statements, see the section called " Forward-Looking Statements." GENERAL We were incorporated in June 1993 under the laws of the State of Texas and currently conduct a majority of our operations as an independent energy company through Coho Resources, Inc. and its subsidiaries. Our crude oil activities are concentrated principally in Mississippi and Oklahoma. We commenced operations in Mississippi in the early 1980s. We acquired our Oklahoma properties from Amoco Production Company in December 1997. At December 31, 2000, approximately 95% of our total proved reserves were comprised of crude oil. Our operating revenues result solely from crude oil and natural gas sales, with crude oil sales representing approximately 77% of production revenues for 1998, 90% of production revenues for 1999 and 91% of production revenues for 2000. Natural gas sales represented approximately 23% of production revenues for 1998, 10% of production revenues for 1999 and 9% of production revenues for 2000. Approximately 60% of natural gas sales revenues during 1998 were attributable to the gas properties located in Monroe, Louisiana, which we sold in December 1998. In August 1999, we filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in order to facilitate a restructuring of our long-term debt. Our plan of reorganization was consummated on March 31, 2000. As a result of the reorganization, our former principal bondholders and their affiliates own 88% of our new common stock. A new management team and a new board of directors have been directing our operations since we emerged from bankruptcy. RESULTS OF OPERATIONS SELECTED OPERATING DATA
1998 1999 2000 -------- -------- -------- PRODUCTION: Crude oil (Bbl/day) ................................. 13,889 9,159 9,658 Natural gas (Mcf/day) ............................... 22,260 7,146 5,702 BOE (Bbl/day) ....................................... 17,599 10,350 10,608 AVERAGE SALES PRICES: Crude oil (per Bbl) ................................. $ 10.40 $ 15.40 $ 23.31 Natural gas (per Mcf) ............................... 1.98 2.24 3.73 PER BOE DATA: Production costs .................................... $ 3.65 $ 4.82 $ 6.06 Production taxes .................................... .53 .78 1.49 Depletion ........................................... 4.38 3.63 3.94 PRODUCTION REVENUES (IN THOUSANDS): Crude oil ........................................... $ 52,689 $ 51,469 $ 82,390 Natural gas ......................................... 16,070 5,854 7,792 -------- -------- -------- Total production revenues ...................... $ 68,759 $ 57,323 $ 90,182 ======== ======== ========
26 27 2000 COMPARED WITH 1999 Operating Revenues. During 2000, production revenues increased 57% to $90.2 million as compared to $57.3 million in 1999. This increase was principally due to a 5% increase in crude oil production, a 51% increase in the price received for crude oil and a 67% increase in the price received for natural gas, including hedging losses discussed below, partially offset by a 20% decrease in natural gas production. During 1999, we experienced overall crude oil production declines in our operated properties due to capital constraints as discussed below in "1999 Compared With 1998." During 2000, we experienced a 5% increase in daily crude oil production as compared to 1999 due to several factors, including: o returning substantially all previously shut-in wells to active service; o recompleting inactive wells and marginal producers; o repairing wells that were previously uneconomical to repair due to depressed crude oil prices; and o increasing drilling activity on our operated properties. The 20% decrease in natural gas production is primarily due to the natural declines on our operated and non-operated gas properties. The effect of natural production declines was partially offset by temporary increases in production due to several recompletions on our operated and nonoperated gas properties that were followed by rapid declines. We experienced a loss of production on our Oklahoma crude oil and natural gas properties on December 27, 2000 due to a full power outage resulting from an ice storm in southern Oklahoma. The main power was restored on January 1, 2001; however, we continued to experience a partial loss of production through January 23, 2001 at which time all wells were restored to production. We estimate the loss of production to be approximately 20,200 BOE during the last four days of December 2000 and approximately 13,300 BOE during January 2001. Average crude oil prices increased 51% during 2000 compared to the same period in 1999, primarily due to strong demand for crude oil during 2000. During the first quarter of 1999, substantially all of our crude oil was sold under contracts that were keyed off of posted crude oil prices. Subsequent to March 1999, substantially all of our Oklahoma crude oil has been sold under contracts that keyed off of the NYMEX price. Our overall average crude oil price per Bbl during 2000 was $23.31, including hedging losses of $2.79 per Bbl as discussed below, which represented a discount of 23% to the average NYMEX price in 2000. Our realized price for our natural gas increased 67% from $2.24 per Mcf in 1999 to $3.73 per Mcf in 2000, including hedging losses of $0.26 per Mcf as discussed below, due to an increase in demand for natural gas during 2000. Production revenues for 2000 included crude oil hedging losses of $9,856,000 ($2.79 per BOE) and natural gas hedging losses of $544,000 ($0.26 per Mcf). Production revenues for 1999 did not include any crude oil or natural gas hedging gains or losses. Expenses. Production expenses were $23.5 million for 2000 compared to $18.2 million for 1999. The increase in expenses from 1999 to 2000 is due primarily to: o increased electrical costs of approximately $1.8 million due to greater fluid movement and higher electrical rates; o increased chemical costs of approximately $609,000 due to increases in production; and o increased well repair costs of approximately $2.2 million due to more extensive repair work and costs to return shut in wells, inactive wells and marginal wells to production and increased costs between years for labor, materials and rigs related to well repair costs of approximately 10%, 5% and 20%, respectively. 27 28 On a BOE basis, production costs increased 26% to $6.06 per BOE in 2000 compared to $4.82 per BOE in 1999. On a BOE basis, production costs increased because the increase in production did not keep pace with the increases in costs discussed above. Additionally, our well repair costs were higher in 2000 because we changed our approach to well repairs. In the past, our approach was generally to only repair any immediate problems with a well. We now evaluate the total condition of the well and repair any immediate problems as well as replace worn parts that may cause additional problems within the next year. Although the upfront repair costs are higher, future repair costs should decrease because the rig cost, which is generally a major cost in well repair work, is only incurred once and downtime for well repairs should decrease. Production taxes increased $2.8 million or 97% to $5.8 million during 2000 as compared to $2.9 million during 1999. This increase is due to increased crude oil production and due to higher realized prices. On a BOE basis, production taxes increased 91% to $1.49 per BOE during 2000 as compared to $.78 per BOE during 1999 due to higher realized prices. General and administrative costs decreased $2.8 million or 28% between the comparable periods. This decrease is primarily due to: o reductions of $2.4 million in employee-related costs, primarily due to the termination of officers and employees in April 2000 in conjunction with our plan of reorganization; o increases in cost recoveries from working interest owners due to an increase in well activity; and o capitalization of $765,000 of salaries and salary related costs associated with exploration and development activities. These decreases were partially offset by increases in professional fees, primarily due to Hicks Muse litigation costs. State income tax penalties of $1.0 million for 1999 resulted from approximately $4 million in Louisiana state income taxes which were due on April 15, 1999, resulting from the gain on the December 1998 sale of the Monroe gas field. The past due taxes include the accrual of the maximum penalty of 25% of the taxes due. Interest expense increased 6% to $36.2 million in 2000 as compared to $33.9 million in 1999. The following is a summary of interest expense between comparable periods:
1999 2000 -------- -------- (in thousands) Old bank group loan .............................. $ 23,673 $ 7,983 Old bond ......................................... 9,275 -- New credit facility .............................. -- 13,434 Standby loan ..................................... -- 10,090 Amortization of debt issuance costs .............. 604 4,597 Miscellaneous .................................... 392 88 -------- -------- $ 33,944 $ 36,192 ======== ========
The increase for the comparable periods relates to several factors including the following: o an effective interest rate of 18.04% on the original $72 million standby loan issued March 31, 2000; o an effective rate of 23.92% on the paid-in-kind interest standby loan issued September 29, 2000; and o higher debt issuance amortization expense resulting from $33.8 million in debt issuance costs on our new debt, including $24.2 million related to the issuance of common stock in connection with the standby loan. These increases were partially offset by: 28 29 o lower interest expense due to a reduction in our debt on March 31, 2000 resulting from the reorganization, o discontinuance of the accrual of interest on our old unsecured bonds as a result of our bankruptcy filing (approximately $3.5 million of additional interest expense would have been recognized during the first quarter of 2000 compared to $5.5 million for 1999, if not for the discontinuance of such interest expense accrual); and o higher interest rates and interest on past due interest on our old bank loan for a shorter period in 2000 as compared to 1999. The average interest rate on outstanding indebtedness was 12.48% in 2000, excluding interest expense related to the embedded derivative, compared to 8.55% in 1999. Interest expense related to the embedded derivative for the year ended 2000 of $15.2 million relates to the change in estimated future additional interest payments calculated on the standby loan. The aggregate amount of the additional interest payments were estimated at March 31, 2000 for the original $72 million standby loan and at September 29, 2000 for the $5.4 million paid-in-kind interest standby loan using the future crude oil and natural gas price curves as of such dates. The aggregate amount of additional interest payments was redetermined at December 31, 2000 using the then current crude oil and natural gas curves. The increase of $15.2 million in the aggregate amount of additional interest payments based on the December 31, 2000 price curves as compared to the aggregate amount of additional interest payments based on the March 31, 2000 and September 29, 2000 price curves was charged to interest expense during 2000. Depletion and depreciation expense increased 11% to $15.2 million in 2000 from $13.7 million in 1999. This increase is primarily the result of increased production volumes and an increased depletion and depreciation rate per BOE, which was $3.94 in 2000, compared with $3.63 in 1999. The depletion and depreciation rate per BOE increased due to an increase in depletable costs and due to a decline in total proved reserves. During 2000, we reclassified unproved property costs totaling $25.7 million that had been excluded from depletable costs as of December 31, 1999 to costs subject to depletion at December 31, 2000. These costs were reclassified because certain of the unproved projects were not viewed as economically attractive by our new management team and will not be performed in the foreseeable future. See "Item 2. Business and Properties - - Oil and Gas Operations-Reserves" for a discussion of the decline in total proved reserves. We have used the full-cost method of accounting for our investment in crude oil and natural gas properties. In accordance with generally accepted accounting principles, at a point in time coinciding with the quarterly and annual reporting periods, we must test the carrying value of our crude oil and natural gas properties, net of related deferred taxes, against the "cost center ceiling." The "cost center ceiling" is a calculated amount based on estimated reserve volumes valued at then-current realized prices held flat for the life of the properties discounted at 10% per annum plus the lower of cost or estimated fair value of unproved properties. If the carrying value exceeds the cost center ceiling, the excess must be expensed in that period and the carrying value of the oil and gas reserves lowered accordingly. Amounts required to be written off may not be reinstated for any subsequent increase in the cost center ceiling. No writedowns of this kind were required on our United States properties in 2000 or 1999. We have decided to discontinue our participation in the exploration of two Tunisia, North Africa permits. In February 2001, the two subsidiaries that own these permits filed for protection under chapter 11 of the United States Bankruptcy Code to preserve our ownership in these permits under the protection of the bankruptcy court while we try to negotiate sales of our interests in the permits to a third party or parties and to reach settlements with respect to our obligations under the permits. As a result, we took a writedown of $3.0 million, representing our remaining carrying costs on these permits, during the fourth quarter of 2000. See "Subsequent Event - Discontinuation of Tunisian Operations" for further discussion on our Tunisian operations. Reorganization costs increased $8.9 million to $12.0 million in 2000 as compared to $3.1 million in 1999. This increase relates to: o professional fees for consultants and attorneys assisting in the negotiations associated with reorganization alternatives and approval and implementation of our plan of reorganization; 29 30 o termination benefits for severed employees; o payments and accrual of settlement amounts for officer employment agreements and officer severance agreements which were rejected in the plan of reorganization; o payments and accrual of amounts made under our retention bonus plan; and o provisions for settlements of disputed bankruptcy claims and other costs to effect the plan of reorganization. Our net operating loss carryforwards for United States and Canadian federal income tax purposes were approximately $118.5 million at December 31, 2000 and expire between 2009 and 2020. Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," requires that the tax benefit of those net operating loss carryforwards be recorded as an asset to the extent that management assesses the utilization of those net operating loss carryforwards to be more likely than not. A valuation allowance has been established for the entire net deferred tax asset balance of these net operating loss carryforwards as it is uncertain whether they will be used before they expire. We experienced an "ownership change" (within the meaning of IRC section 382) on the effective date of the plan of reorganization as a result of the issuance of new common stock to certain holders of claims. Our ability to use any pre-effective date NOLs and capital loss carryovers to offset income in any post-effective date taxable year (and in the portion of the taxable year of the ownership change following the effective date) to which such a carryover is made (subject to various exceptions and adjustments) will be limited, resulting in an estimated $33.0 million of NOL's which are expected to expire due to the IRC section 382 limitation. Due to the factors discussed above, our net loss for 2000 was $32.7 million, as compared to a net loss of $30.7 million for 1999. The losses include writedowns of our Tunisian oil and gas properties of $3.0 million and $5.4 million for 2000 and 1999, respectively. 1999 COMPARED WITH 1998 Operating Revenues. During 1999, production revenues decreased 17% to $57.3 million as compared to $68.8 million in 1998. This decrease was principally due to a 34% decrease in crude oil production and a 68% decrease in natural gas production, substantially offset by increases of 48% in the price received for crude oil and 13% in the price received for natural gas, including hedging gains and losses discussed below. The 68% decrease in daily natural gas production during 1999 was primarily due to the December 1998 sale of the Monroe field gas properties which accounted for 67% of our natural gas production during 1998. The 34% decrease in daily crude oil production during 1999 is due to overall production declines in the Mississippi and Oklahoma properties that we operate. Due to our capital constraints caused by the decline in crude oil prices during 1998, we: o significantly reduced both minor and major well repairs and drilling activity on our operated properties during the last five months of 1998; o ceased all well repairs and drilling activity in December 1998; and o halted production on wells which were uneconomical due to depressed crude oil prices. All of these actions contributed to our overall production declines. From May 1999 through December 1999 we used working capital provided by operations to perform well repair work to return some of our shut-in wells to production in response to the improved crude oil prices in the second quarter of 1999. Average crude oil prices increased 48% during 1999 compared to the same period in 1998. During 1998 and the first quarter of 1999, substantially all of our crude oil was sold under contracts which were keyed off of posted crude oil prices. Beginning in April 1999, we entered into a new crude oil contract for substantially all of our Oklahoma crude oil, now keyed off of the NYMEX price, which resulted in a net increase in our realized price. Our overall average crude oil price per Bbl was $15.40, which represented a discount of 20% to the average NYMEX price in 1999. 30 31 Our realized price for our natural gas, including hedging losses discussed below, increased 13% from $1.98 per Mcf in 1998 to $2.24 per Mcf in 1999 due to an increase in demand for natural gas during 1999. Production revenues for 1999 and 1998 did not include any crude oil hedging gains or losses. Production revenues in 1999 did not include any natural gas hedging gains or losses compared to natural gas hedging gains of $488,000 ($0.06 per Mcf) for 1998. Expenses. Production expenses, including production taxes, were $21.2 million for 1999 compared to $26.9 million for 1998. The decrease in expenses between years is primarily due to: o decreased production; o decreased production taxes; and o the December 1998 sale of the Monroe properties. On a BOE basis, production costs increased 34% to $5.60 per BOE in 1999 compared to $4.18 per BOE in 1998. On a BOE basis, the increase in production costs is primarily due to a decrease in production volumes, which resulted in a higher fixed cost per BOE, and $3.3 million of well repair work performed during the last half of 1999 to return shut-in wells to production. Additionally, severance taxes increased $0.25 per BOE during 1999 as compared to 1998 due to higher price realization. The well repair work represented an accumulation of projects because we had reduced both minor and major well repairs during the last five months of 1998 and ceased substantially all well repair work in December 1998 due to depressed oil prices. General and administrative costs increased $2.2 million or 28% between the comparable periods. This increase is primarily due to the expensing of all salaries and other general and administrative costs associated with exploration and development activities during 1999 as compared to the capitalization of $5.7 million of these costs in 1998. Total general and administrative costs, excluding capitalization of administrative costs associated with exploration and development activities, decreased $3.6 million or 27% between the comparable periods. This decrease is primarily due to: o cost reductions associated with the Monroe field sale; o reductions in employee-related costs due to staff attrition; o reductions in estimated franchise tax accruals as a result of our losses in 1998; and o reductions in professional fees and general corporate costs. These decreases were partially offset by lower cost recoveries from working interest owners due to a decrease in well activity. State income tax penalties of $1.0 million for 1999 result from approximately $4 million in Louisiana state income taxes which were due on April 15, 1999, resulting from the gain on the December 1998 sale of the Monroe gas field. The past due taxes include the accrual of the maximum penalty of 25% of the taxes due. Interest expense increased 3% in 1999 compared to 1998 primarily as a result of higher interest rates from payment defaults and debt acceleration, partially offset by the discontinuance of interest expense accruals on our unsecured debt. On August 24, 1999, we discontinued the accrual of interest on our unsecured debt as a result of our Chapter 11 filing. We would have recognized approximately $5.7 million of additional interest expense in 1999, including $2.2 million of interest on our old bonds that would have been due on October 15, 1999, if not for the discontinuation of these interest expense accruals. The average interest rate on outstanding indebtedness was 8.55% in 1999, compared to 8.07% in 1998. Depletion and depreciation expense decreased 51% to $13.7 million in 1999 from $28.1 million in 1998. This decrease is primarily the result of decreased production volumes and a decreased depletion and depreciation rate per BOE, which was $3.63 in 1999, compared with $4.38 in 1998. The depletion and depreciation rate per BOE 31 32 decreased between 1998 and 1999 due to the writedowns of oil and gas properties in 1998 as discussed in the next paragraph. During 1998, the carrying values related to our United States properties exceeded the cost center ceilings, resulting in non-cash writedowns of our crude oil and natural gas properties of $188 million. These writedowns resulted from the declines in crude oil prices in 1998. No writedowns of this kind were required on our United States properties in 1999. In June 1999, we commenced drilling an exploratory well on our Anaguid permit in Tunisia, North Africa, due to our obligation under the permit. In September 1999, we tested the well and determined that the well would not produce sufficient quantities of crude oil to justify further completion work on it. As a result, we took a writedown of our Tunisian properties of $5.4 million during the third quarter of 1999. Reorganization costs of $3.1 million in 1999 relate to professional fees for consultants and attorneys assisting us in the negotiations associated with our financing and reorganization alternatives and are partially offset by interest income earned since August 23, 1999, on accumulated cash. Due to the factors discussed above, our net loss for 1999 was $30.7 million, as compared to a net loss of $203.3 million for 1998. The 1999 loss includes a writedown of our Tunisian oil and gas properties of $5.4 million and the 1998 loss includes writedowns of our United States crude oil and natural gas properties of $188.0 million. LIQUIDITY AND CAPITAL RESOURCES Reorganization. On August 23, 1999, we and our wholly-owned subsidiaries, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production Company and Interstate Natural Gas Company, filed a voluntary petition for relief under Chapter 11 of the U. S. Bankruptcy Code. We then filed a plan of reorganization that was confirmed by the bankruptcy court on March 20, 2000. On March 31, 2000, the plan of reorganization was consummated and we emerged from bankruptcy. The reorganized value of our assets exceeded the total of all postpetition liabilities and allowed claims; therefore, we did not qualify for fresh-start accounting. We recorded the following transactions to effect our plan of reorganization consummated on March 31, 2000: o The borrowing of $183.0 million under our new credit facility. o The borrowing of $72.0 million under the standby loan and the issuance of 2,694,841 shares of new common stock as debt issuance costs valued at $24.2 million. o Repayment of borrowings outstanding under the old bank credit facility together with accrued interest and fees totaling $260.2 million, resulting in a $303,000 loss on extinguishment of debt. o Conversion of the old bonds into 15,362,107 shares of new common stock, representing 82% of the new common stock. Although the old bonds were paid no more than in full, we did realize a loss on extinguishment of debt of $4.1 million because our carrying value of the old bonds was less than the allowed claim, primarily due to unamortized debt issuance costs. o Provision of $1.6 million to allow for settlement of disputed claims. Substantially all of the bankruptcy claims and bankruptcy costs were paid during 2000 with a final installment payment on unsecured claims being paid on January 2, 2001. Priority tax claims totaling approximately $5.2 million received five-year, interest-bearing promissory notes under our plan of reorganization. As a result of the reorganization, our former bondholders and their affiliates own approximately 88% of our new common stock and own $65.5 million of the outstanding notes issued under the original $72 million standby loan. Capital Sources. During 2000, cash flow provided by operating activities was $9.9 million compared with cash flow provided by operating activities of $14.9 million for the same period in 1999. Operating revenues, net of lease 32 33 operating expenses, production taxes and general and administrative expenses, increased $27.5 million from $26.3 million in 1999 to $53.7 million in 2000, primarily due to: o price increases between such comparable periods of 51% and 67% for crude oil and natural gas, respectively; o increases in crude oil production; and o reductions in general and administrative expenses. The increases in net operating revenue as a result of these price and production increases and general and administrative expense reductions were partially offset by increases in production expenses and production taxes between comparable periods. We also incurred costs totaling $12.0 million during 2000 related to reorganization costs. Changes in operating assets and liabilities used $11.7 million of cash for operating activities for 2000, compared to $25.8 million of cash for operating activities provided for the same period in 1999, primarily due to payment of $18.5 million in accrued interest payable and the reclassification of $4.1 million of accrued state income taxes and penalties from liabilities subject to compromise to long-term debt, partially offset by increases in accrued reorganization costs, and other accrued liabilities and increased accounts receivables from purchasers due to higher crude oil and natural gas prices. See "Results of Operations" for a discussion of operating results. Working Capital. We had a working capital deficit of $2.6 million at December 31, 2000 compared to working capital, before liabilities subject to compromise, of $16.2 million at December 31, 1999. The decrease in working capital relates to several factors including the following: o Cash balances on hand decreased from $18.8 million at December 31, 1999 to $6.7 million at December 31, 2000. The decrease in cash is primarily due to the utilization of cash accumulated during bankruptcy to consummate the reorganization. o Current liabilities increased from $15.2 million at December 31, 1999 to $22.4 million at December 31, 2000 due to several factors including: o the reclassification of $1.4 million of liabilities subject to compromise to current liabilities as a result of our emergence from bankruptcy; o an increase of $2.6 million in trade payables primarily due to increased drilling and well repair activities subsequent to our emergence from bankruptcy; o an increase of $1.3 million in accrued reorganization costs; o an increase of $1.0 million in current long-term debt related to the current maturities under the five-year notes to be issued in settlement of priority tax claims; o an increase of $1.2 million in current environmental liabilities related to the bankruptcy claims; " an increase of $507,000 in accrued liabilities related to a reserve established for disputed claims settlements; o an increase of $3.4 million in accrued liabilities related to operations; and o an increase of $900,000 in accrued liabilities related to hedging losses. The above factors were partially offset by a reduction in accrued interest of $6.1 million related to our bank credit facilities. Credit Facilities. We and some of our subsidiaries were parties to an old bank group loan agreement. Borrowings outstanding under the old bank group loan, together with accrued interest and reasonable fees totaling $260.2 million, were paid on March 31, 2000. We obtained the funds necessary for the payment of the old bank group loan through the combination of borrowings under the new senior revolving credit facility, borrowings under the standby loan and from cash on hand. Additionally, we owed approximately $162 million of principal and accrued interest under our old bond indenture. Under the plan of reorganization, these old bonds and accrued interest were converted into 15,362,107 shares of new common stock. 33 34 The new senior revolving credit facility was obtained from a syndicate of lenders led by The Chase Manhattan Bank, as agent for the new lenders, and has a principal amount of up to $250 million. The new credit facility limits advances to the amount of the borrowing base, which is currently at $205 million. At December 31, 2000, $180 million was outstanding under this bank facility. The borrowing base is the loan value assigned to the proved reserves attributable to our oil and gas properties. The new credit facility is subject to semiannual borrowing base redeterminations each April 1 and October 1, based on our reserve reports, and will be made at the sole discretion of the lenders. We or Chase may each request one additional borrowing base redetermination during any calendar year. Interest on advances under the new credit facility will be payable on the earlier of the expiration of any interest period under the new credit facility or quarterly. Amounts outstanding under the new credit facility will accrue interest at our option at either the Eurodollar rate, which is the annual interest rate equal to the London interbank offered rate ("LIBOR") for deposits in United States dollars that is determined by reference to the Telerate Service or offered to Chase plus an applicable margin (currently 3%), or the prime rate, which is the floating annual interest rate established by Chase from time to time as its prime rate of interest plus an applicable margin (currently 2%). All outstanding advances under the new credit facility are due and payable on March 31, 2003. The new credit facility has been secured by granting Chase the following collateral for the benefit of the lenders: o first and prior security interests in the issued and outstanding capital stock and other equity interests of our material subsidiaries; o first and prior mortgage liens and security interests covering proved mineral interests selected by Chase having a present value, as determined by Chase, of not less than 85% of the present value of all our proved mineral interests evaluated by the lenders for purposes of determining the borrowing base; and o first and prior security interests in our other tangible and intangible assets. The new credit agreement contains financial and other covenants including: o maintenance of required ratios of cash flow to interest expense paid or payable in cash (2 to 1 for the average of the last four consecutive quarters most recently ended December 31, 2000, gradually increasing to 3 to 1 for quarters ending after January 1, 2002), senior debt to cash flow required (not to exceed 5 to 1 for the average of the last four consecutive quarters most recently ended December 31, 2000, gradually decreasing to 3.5 to 1 for any quarter ending after January 1, 2002), and current assets (including unused borrowing base) to current liabilities required (throughout the term of the credit agreement, to be 1 to 1 as of the end of each quarter); o restrictions on the payment of dividends; and o limitations on the incurrence of additional indebtedness, the creation of liens and the incurrence of capital expenditures. The lenders received an additional $5.8 million of closing fees in addition to expense reimbursements. The standby loan was made under a senior subordinated note facility under which we issued $72 million of senior subordinated notes to PPM America, Inc., Appaloosa Management, L.P., Oaktree Capital Management, L.L.C., Pacholder Associates, Inc. and their respective assignees. Our rights and responsibilities and those of the standby lenders are governed by a standby loan agreement which was executed and delivered on March 31, 2000. Debt under the standby loan agreement is evidenced by notes maturing March 31, 2007 and bearing interest at a minimum annual rate of 15% and payable in cash semiannually. After March 31, 2001, additional semiannual interest payments will be payable in an amount equal to 1/2% for every $0.25 that the "actual price" for our oil and gas production exceeds $15 per barrel of oil equivalent during the applicable semiannual interest period, up to a maximum of 10% additional interest per year. The "actual price" for our oil and gas production is the weighted average price received by us for all our oil and gas production, including hedged and unhedged production, net of hedging costs, in dollars per barrel of oil equivalent using a 6:1 conversion ratio for natural gas. The actual price will be calculated over a six-month measurement period ending on the date two months before the applicable interest 34 35 payment date. Additionally, upon an event of default occurring under the standby loan, interest will be payable in cash, unless otherwise required to be paid-in-kind, at a rate equal to 2% per year over the applicable interest rate. Interest payments under the standby loan may be paid-in-kind subject to the requirements of the intercreditor arrangement between the standby lenders and the lenders under the new credit agreement. "Paid-in-kind" refers to the payment of interest owed under the standby loan by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. The semiannual standby loan interest payment due on September 29, 2000 was paid-in-kind and has been reflected as an increase in long-term debt. The additional semiannual interest payment feature of the standby loan agreement based on the actual price received for our oil and gas production, as discussed above, is considered an embedded derivative instrument. The additional interest cost associated with this embedded derivative instrument is calculated at the origination of each loan and at each future balance sheet date. The aggregate amount of the additional interest payments on the original $72 million standby loan was estimated at its inception date, using the future crude oil and natural gas price curves as of such date. These estimated additional interest payments were added to interest payments due based on the minimum annual rate at 15% to determine an effective interest rate of 18.04% for the term of the original $72 million standby loan. In addition, the same procedures were applied to the standby loan of $5.4 million issued on September 29, 2000 to determine an effective rate of 23.92% for the term of this loan. The aggregate amount of the additional interest payments due on each loan was redetermined at December 31, 2000 using the then current future crude oil and natural gas price curves. The difference of $15.2 million in the amount of additional interest payments based on the December 31, 2000 price curves as compared to the aggregate amount of additional interest payments based on the price curves at the inception date of each loan was reflected as an increase in the standby loan debt and a charge to interest expense during 2000. The additional interest expense may continue to have significant volatility from period to period based on the changes in the futures price curves from period to period. For further discussion on the future volatility of interest expense, see " Hedging Activities and Other Derivatives". Payment of the standby loan notes will be expressly subordinate to payments in full in cash of all obligations arising in connection with the new credit facility. After the initial 12-month period, cash interest payments may be made only to the extent by which EBITDA, or earnings before interest, tax, depreciation and amortization expense, on a trailing four-quarter basis exceed $65 million. The new credit agreement also prohibits us from making any cash interest payments on the standby loan indebtedness if the outstanding indebtedness under both the new credit facility and the standby loan exceeds 3.75 times EBITDA for the trailing four quarters. We do not currently meet the requirements to make cash interest payments on the standby loan indebtedness. We may prepay the standby loan notes at the face amount, in whole or in part, in minimum denominations of $1,000,000, plus either a standard make-whole payment at 300 basis points over the "treasury rate" for the first four years, beginning in the fifth year, a prepayment fee of 7.5% of the principal amount being prepaid; in the sixth year, a prepayment fee of 3.75% of the principal amount being prepaid; and after the sixth year there is no prepayment fee. The "treasury rate" is the yield of U.S. Treasury securities with a term equal to the then-remaining term of the standby loan notes that has become publicly available on the third business day before the date fixed for repayment. As of December 31, 2000, the prepayment fee was approximately $24.6 million. When the standby loan notes were issued on March 31, 2000, the standby lenders became entitled to receive 14.4% of our fully diluted new common stock valued at approximately $24.2 million. The shares were registered with the Securities and Exchange Commission in connection with the rights offering and were issued on June 1, 2000. The shares of new common stock issued to the standby lenders were in addition to the shares of new common stock issued to holders of the old bonds, to our shareholders prior to reorganization and to persons participating in the rights offering. Additionally, the standby lenders received closing fees of approximately $2.5 million as well as expense reimbursements. Operating Plan. We have a high level of indebtedness after the reorganization. Our total consolidated indebtedness as of December 31, 2000 was $282.4 million and the ratio of total consolidated indebtedness to total capitalization was 82%. Due to our high level of indebtedness, our new management team developed an operating plan for 2000 and 2001 that focuses on capital projects that we believe will generate increases in: o production; o cash flow from operations; and 35 36 o our proved developed producing crude oil and natural gas reserves and, to a lesser extent, total proved reserves. Management believes that forecasted operating revenues, assuming conservative growth in production and conservative commodity prices as compared to current commodity prices, and availability under the new credit facility will be sufficient to fund the following forecasted expenditures through the end of the year 2001: o operating expenses, including well repair costs; o general and administrative expenses; o interest due under the bank credit facility; o capital expenditures; and o other current obligations. Interest owed under the standby loan will be "paid-in-kind" by increasing the amount of principal outstanding through the issuance of additional standby loan notes. Recapitalization. As mentioned above, we are highly leveraged with a ratio of total consolidated indebtedness to total capitalization of 82%. Interest due under our standby loan starts accruing at a 25% rate on April 1, 2001 based on current crude oil and natural gas prices. Although we currently have adequate sources of liquidity for the budgeted activities that we expect to conduct in 2001, this high level of indebtedness has several important effects on our future operations, including: o requiring us to devote a substantial portion of our cash flow from operations to pay interest on our indebtedness and not for other uses, such as funding working capital or capital expenditures; o limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes thereby restricting our future growth; o putting us at a competitive disadvantage to our competitors who have less debt than us; and o limiting our flexibility to plan for, or to react to, changes in our business and the oil and gas industry. We are exploring alternatives to reduce our leverage ratio. Our alternatives include, but are not limited to: o entering into an equity transaction with another company with a lower leverage ratio; o raising additional equity to repay all or a substantial portion of our indebtedness outstanding under the standby loan; o converting all or a substantial portion of the standby loan to equity; or o combining one or more of these various alternatives. Dividends. It is unlikely that we will pay dividends in the foreseeable future. The terms of the new credit facility and the standby loan restrict our paying dividends. Capital Expenditures. During 2000, we incurred capital expenditures of $25.3 million compared with $6.3 million for the same period in 1999. We ceased substantially all of our capital projects in 1999 due to our liquidity problems and our bankruptcy filing, as discussed above; however, during 2000 we have increased capital expenditure activities and we expect to continue work on capital projects. The expenditures incurred during 2000 were largely in connection with development efforts, including recompletions, workovers and waterfloods on existing wells throughout the Oklahoma and Mississippi fields. In addition, during 2000, we drilled 23 wells as follows: 36 37 Mississippi Fields: Brookhaven - 1 producing oil; 1 dry hole Martinville - 1 producing oil Oklahoma Fields: Tatums - 10 producing oil; 1 service well Cox Penn - 2 producing oil East Fitts - 1 producing oil Graham-Deese - 1 producing gas; 1 dry hole Eola - 1 producing oil; 1 dry hole Sholem Alechem - 1 producing gas Non-operated fields - 1 producing gas. A $40.2 million capital expenditures budget for the year 2001 has been approved by our board of directors, which will be funded by working capital from operations and borrowings under the new credit facility. We have no material capital commitments related to our United States operations and are consequently able to adjust the level of our expenditures based on available cash flow. No general and administrative costs associated with our exploration and development activities were capitalized for 1999 compared with $765,000 of capitalized costs for 2000. Hedging Activities and Other Derivatives. Crude oil and natural gas prices are subject to significant seasonal, political and other variables which are beyond our control. In an effort to reduce the effect of the volatility of the prices received for crude oil and natural gas, we have entered, and expect to continue to enter, into crude oil and natural gas hedging transactions. Additionally, our new bank credit facility required us to hedge 75% of our crude oil production as of March 31, 2000 within ten days of such date for a two-year period. The bank credit facility also limits our hedging to 85% of crude oil production. While our hedging program is intended to stabilize cash flow and thus allow us to plan our capital expenditure program with greater certainty, any hedging transactions may limit our potential gains if crude oil and natural gas prices rise substantially over the price established by the hedge. Because all hedging transactions are tied directly to our crude oil and natural gas production, we do not believe that these transactions are of a speculative nature. Gains and losses on these hedging transactions are reflected in crude oil and natural gas revenues at the time of sale of the hedged production. Any gain or loss on our crude oil hedging transactions is determined as the difference between the contract price and the average closing price for West Texas Intermediate crude oil on the New York Mercantile Exchange for the contract period. Any gain or loss on our natural gas hedging transactions is generally determined as the difference between the contract price and the New York Mercantile Exchange Henry Hub settlement price the next to last business day of the contract. Consequently, hedging activities do not affect the actual price received for our crude oil and natural gas. At December 31, 2000, using the then current price curves, we had $5,078,000 in estimated unrealized losses. Based on 2000 production levels, 22% of our 2001 natural gas production, 85% of our 2001 crude oil production and 29% of our 2002 crude oil production have been hedged as follows: Minimum and Maximum Crude Oil Price Arrangements o 6,000 barrels per day for the period January 1, 2001 to June 30, 2001, with a minimum price of $21.00 and a maximum price of $24.50. o 2,000 barrels per day for the period January 1, 2001 to December 31, 2001, with a minimum price of $26.00 and a maximum price of $30.70. o 250 barrels per day for the period January 1, 2001 to June 30, 2001, with a minimum price of $20.00 and a maximum price of $22.65. o 6,250 barrels per day for the period July 1, 2001 to December 31, 2001, with a minimum price of $20.00 and a maximum price of $22.80. o 500 barrels per day for the period January 1, 2002 to December 31, 2002, with a minimum price of $22.00 and a maximum price of $28.00. 37 38 o 500 barrels per day for the period January 1, 2002 to December 31, 2002, with a minimum price of $22.00 and a maximum price of $29.60. o 500 barrels per day for the period January 1, 2002 to December 31, 2002, with a minimum price of $24.00 and a maximum price of $28.60. Fixed Price Crude Oil Arrangements o 5,500 barrels per day for the period January 1, 2002 to March 31, 2002 with a fixed price of $20.40. Minimum and Maximum Natural Gas Price Arrangements o 3,000 MMbtus per day for the period January 1, 2001 to May 31, 2001, with a minimum price of $3.35 and a maximum price of $4.01. We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" effective January 1, 2001. The Statement will require us to recognize all derivative instruments (including certain derivative instruments embedded in other contracts) on the balance sheet as either an asset or liability based on fair value on January 1, 2001. Subsequent changes in fair value for the effective portion of derivatives qualifying as hedges will be recognized in other comprehensive income until the hedged item is recognized in earnings, at which time, changes in fair value previously recognized in other comprehensive income will be reclassified to earnings. Subsequent changes in fair value for the ineffective portion of derivatives qualifying as hedges and for derivatives that are not hedges must be adjusted to fair value through earnings. Our hedge arrangements, as discussed above, qualify as cash flow hedges under SFAS No. 133. The estimated fair value of these hedge arrangements represented a net liability of approximately $5.8 million at December 31, 2000, which will be recorded on the balance sheet effective January 1, 2001, with an offsetting amount in accumulated other comprehensive loss. We have entered into certain lease agreements in Laurel, Mississippi, which contain provisions for lease payments which are to be calculated based on crude oil prices. These arrangements are considered to include embedded derivatives under SFAS No. 133. The estimated fair value of these embedded derivatives represented a net liability of approximately $300,000 at December 31, 2000, which will be recorded on the balance sheet effective January 1, 2001, with an offsetting amount in accumulated effect of an accounting change. Our standby loan agreement, as discussed above under "Credit Facilities", contains an additional semiannual interest feature which is calculated based on the actual price we receive for our oil and gas production. The additional interest feature of the standby loan agreement is considered an embedded derivative under SFAS No. 133. Based on our current fair valuation method, as discussed below in "Item 7A - Quantitative and Qualitative Disclosure about Market Risk", adoption of SFAS No. 133 on January 1, 2001 will result in a decrease in the existing liability at December 31, 2000 of approximately $5.5 million with an offsetting amount to accumulated effect of an accounting change; however, due to the complexity of this embedded derivative instrument, we are still evaluating our method of determining fair value. Subsequent Event- Discontinuation of Tunisian Operations. We have decided to discontinue our participation in the exploration of two Tunisia, North Africa permits due to required capital commitments during 2001 exceeding $7 million net to our interest, including cash calls currently due totaling $753,000 for January and February on the Anaguid permit. We own a 45.8% interest in the Anaguid permit operated by Anadarko Tunisia Anaguid Company and a 12.5% interest in the Fejaj permit operated by Bligh Tunisia, Inc. We have been actively marketing our interests in these two permits since emerging from bankruptcy in March 2000 but have not been successful in selling such interests. We believe it is in our best interest to preserve our ownership in these permits under the protection of the bankruptcy court while we attempt to negotiate sales of our interests in the permits to a third party or parties and to reach settlements with respect to our obligations under the permits. Therefore, the two subsidiaries that own these permits, Coho Anaguid, Inc. and Coho International Limited, filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001. We anticipate that the other interest owners in these Tunisian permits will claim that these two subsidiaries are obligated for their share of the 2001 capital commitments totaling in excess 38 39 of $7 million under the terms of the related operating and permit agreements. We are unable to determine the amount we may ultimately have to pay related to the 2001 capital commitments or the amount we may receive if we are successful in selling our Tunisia interests. Accordingly, no accrual for the resolution of these uncertainties has been made at December 31, 2000. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We use financial instruments which inherently have some degree of market risk. The primary sources of market risk include fluctuations in commodity prices and interest rate fluctuations. PRICE FLUCTUATIONS Our results of operations are highly dependent upon the prices received for crude oil and natural gas production. We have entered, and expect to continue to enter, into forward sale agreements or other arrangements for a portion of our crude oil and natural gas production to hedge our exposure to price fluctuations. At December 31, 2000, we have hedged a portion of our crude oil and natural gas production through December 31, 2002. To calculate the potential effect of the hedging contracts on our revenues, we applied prices from December 31, 2000 future oil and gas price curves for 2001 and 2002 to the quantity of our oil and gas production hedged for these periods. In addition, we applied December 31, 2000 future oil and gas pricing from the price curves assuming a 10% increase in prices and assuming a 10% decrease in prices. The estimated changes in our revenue through December 31, 2002 resulting from the hedging contracts are as follows:
2001 2002 ------------ ------------ Increase (decrease) based on current price curve $ (3,785,000) $ (1,293,000) Increase (decrease) based on 10% decrease in price curve $ 1,187,000 $ 811,000 Increase (decrease) based on 10% increase in price curve $(10,687,000) $ (2,665,000)
Total debt as of December 31, 2000 included $77.4 million in debt under our standby loan agreement, which represents the original $72 million standby loan issued March 31, 2000 and a subsequent loan made on September 29, 2000 of $5.4 million. The standby loan bears interest at a minimum rate of 15% payable semiannually and after March 31, 2001, additional semiannual interest payments payable in an amount equal to 1/2% for every $0.25 that the actual price, net of hedging costs, for our oil and gas production exceeds $15.00 per barrel of oil equivalent during the applicable semiannual interest period, up to a maximum of 10% additional interest per year. The estimated fair value of the standby loans at December 31, 2000 of $87.0 million represents the discounted value of total future estimated payments due under the original standby loan issued on March 31, 2000 and the subsequent loan for payment of paid-in-kind interest issued on September 29, 2000, using the future crude oil and natural gas price curves at December 31, 2000. The discount factor for the original standby loan and the subsequent standby loan of 18.04% and 23.92%, respectively, which were used in this valuation were determined based on the discount applied at the inception of each loan. The applied discounts of 18.04% and 23.92% were calculated at each loan's inception date by using the total future estimated payments due under the standby loan including additional interest payments estimated over the life of the standby loan, using the future crude oil and natural price curves at each loan's inception date as compared to the initial borrowings under the standby loan and subsequent loan of $72 million and $5.4 million, respectively. At each balance sheet date, the future additional interest payments are calculated using the then current future crude oil and natural gas price curves. The change in the total future additional interest payments is charged to interest expense; therefore, changes in crude oil and natural gas prices can cause a significant change in earnings. At December 31, 2000, based on current debt outstanding, we calculated estimated additional interest payments under the standby loan agreement, using the December 31, 2000 price curves. These additional interest payments represent an amount equal to 1/2% for every $0.25 that the actual price received for our oil and gas production exceeds $15.00 per barrel of oil equivalent up to a maximum of 10%, as discussed above, beginning April 1, 2001. The estimated increase in interest expense through December 31, 2001 relating to the additional interest under the standby loan agreement is $5.8 million using the December 31, 2000 price curves, which represents the maximum amount of additional interest under the terms of the standby loan agreement. If the December 31, 2000 price curves increase or decrease by 10%, the additional interest accruing on the standby loan would remain at the maximum 39 40 amount of $5.8 million during 2001. Interest payments under the standby loan agreement may be paid-in-kind by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for discussion on interest payments to be paid-in-kind. INTEREST RATE RISK Total debt as of December 31, 2000, included $180 million of floating-rate debt attributed to bank credit facility borrowing. As a result, our annual interest cost in 2001 will fluctuate based on short-term interest rates. The impact on annual cash flow of a ten percent change in the floating interest rate (approximately 98 basis points) would be approximately $1.8 million assuming outstanding debt of $180 million throughout the year. We have locked in a rate of 9.75% (6.75% LIBOR plus 3% margin) thru April 9, 2001 on $180 million of bank credit facility borrowings. 40 41 ITEM 8. FINANCIAL STATEMENTS Report of Independent Public Account...................................................................... 42 Consolidated Balance Sheets, December 31, 1999 and 2000................................................... 43 Consolidated Statements of Operations, Years Ended December 31, 1998, 1999 and 2000....................... 44 Consolidated Statements of Shareholders' Equity, Years Ended December 31, 1998, 1999 and 2000............. 45 Consolidated Statements of Cash Flows, Years Ended December 31, 1998, 1999 and 2000....................... 46 Notes to Consolidated Financial Statements, Years Ended December 31, 1998, 1999 and 2000.................. 47
41 42 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Shareholders of Coho Energy, Inc. We have audited the accompanying consolidated balance sheets of Coho Energy, Inc. and subsidiaries as of December 31, 1999 and 2000, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Coho Energy, Inc. and subsidiaries as of December 31, 1999 and 2000, and the results of its operations and cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States. Arthur Andersen LLP Dallas, Texas March 27, 2001 42 43 COHO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS) ASSETS
DECEMBER 31 ----------------------- 1999 2000 --------- --------- Current assets Cash and cash equivalents .............................................. $ 18,805 $ 6,661 Cash in escrow ......................................................... 78 1,042 Accounts receivable, principally trade ................................. 11,158 11,517 Other current assets ................................................... 1,428 483 --------- --------- 31,469 19,703 Property and equipment, at cost net of accumulated depletion and depreciation, based on full cost accounting method (note 3) ............ 311,788 317,667 Other assets .............................................................. 5,544 29,421 --------- --------- $ 348,801 $ 366,791 ========= ========= LIABILITIES AND SHAREHOLDERS' EQUITY Liabilities not subject to compromise: Current liabilities Accounts payable, principally trade .................................. $ 1,294 $ 5,343 Accrued liabilities and other payables ............................... 2,959 9,773 Accrued reorganization costs ......................................... 792 2,120 Accrued interest ..................................................... 10,175 4,078 Current portion of long term debt (note 4) ........................... -- 1,036 --------- --------- Total current liabilities ....................................... 15,220 22,350 Liabilities subject to compromise: Accounts payable, principally trade .................................. 4,166 -- Accrued liabilities and other payables ............................... 5,373 -- Accrued interest ..................................................... 21,379 -- Accrued state income taxes payable ................................... 4,136 -- Current portion of long term debt (note 4) ........................... 388,685 -- --------- --------- Total liabilities subject to compromise ......................... 423,739 -- --------- --------- 438,959 22,350 --------- --------- Long-term debt, excluding current portion (note 4) ........................ -- 282,412 --------- --------- Commitments and contingencies (note 10) ................................... 1,800 520 Shareholders' equity (note 8) Preferred stock, par value $0.01 per share Authorized 10,000,000 shares, none issued ........................... -- -- Common stock, par value $0.01 per share Authorized 50,000,000 shares Issued and outstanding 640,088 (restated) and 18,714,175 shares ..... 256 187 Additional paid-in capital ............................................. 137,812 324,070 Retained deficit ....................................................... (230,026) (262,748) --------- --------- Total shareholders' equity ..................................... (91,958) 61,509 --------- --------- $ 348,801 $ 366,791 ========= =========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 43 44 COHO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31 --------------------------------------- 1998 1999 2000 --------- --------- --------- Operating revenues Net crude oil and natural gas production .......................... $ 68,759 $ 57,323 $ 90,182 --------- --------- --------- Operating expenses Crude oil and natural gas production .............................. 23,475 18,218 23,542 Taxes on oil and gas production ................................... 3,384 2,937 5,778 General and administrative (note 3) ............................... 7,750 9,905 7,137 State income tax penalties ........................................ -- 1,048 -- Allowance for bad debt ............................................ 894 -- 765 Unsuccessful transaction costs .................................... 2,129 -- -- Depletion and depreciation ........................................ 28,135 13,702 15,316 Writedown of crude oil and gas properties ......................... 188,000 5,433 3,027 --------- --------- --------- Total operating expenses ..................................... 253,767 51,243 55,565 --------- --------- --------- Operating income (loss) .............................................. (185,008) 6,080 34,617 --------- --------- --------- Other income and expenses Interest and other income ......................................... 214 246 448 Interest expense (note 4) ......................................... (32,935) (33,944) (36,192) Interest expense related to embedded derivative (note 4) .......... (--) (--) (15,163) --------- --------- --------- 32,721 (33,698) (50,907) --------- --------- --------- Loss from operations before reorganization costs, income taxes and extraordinary items ........................................... (217,729) (27,618) (16,290) --------- --------- --------- Reorganization costs (note 2) ........................................ -- 3,123 12,004 --------- --------- --------- Loss from operations before income taxes and extraordinary item ...... (217,729) (30,741) (28,294) --------- --------- --------- Income taxes (note 6) Current (benefit) expense ......................................... 4,111 (26) -- Deferred (benefit) expense ........................................ (18,494) -- -- --------- --------- --------- (14,383) (26) -- --------- --------- --------- Loss before extraordinary item ....................................... (203,346) (30,715) (28,294) Extraordinary item - loss on extinguishment of indebtedness (note 2) .......................................................... -- -- (4,428) --------- --------- --------- Net loss ............................................................. $(203,346) $ (30,715) $ (32,722) ========= ========= ========= Basic and diluted loss per common share (note 1) Loss before extraordinary item .................................... $ (317.68) $ (47.99) $ (1.98) Extraordinary item ................................................ $ -- $ -- $ (0.31) Net loss .......................................................... $ (317.68) $ (47.99) $ (2.29)
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 44 45 COHO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS, EXCEPT SHARE AMOUNTS)
NUMBER OF COMMON ADDITIONAL RETAINED SHARES COMMON PAID-IN EARNINGS OUTSTANDING STOCK CAPITAL (DEFICIT) TOTAL ----------- ----------- ----------- ----------- ----------- Balance at December 31, 1997 .................. 25,603,512 $ 256 $ 137,812 $ 4,035 $ 142,103 Net loss ................................... -- -- -- (203,346) (203,346) ----------- ----------- ----------- ----------- ----------- Balance at December 31, 1998 .................. 25,603,512 256 137,812 (199,311) (61,243) Net loss ................................... -- -- -- (30,715) (30,715) ----------- ----------- ----------- ----------- ----------- Balance at December 31, 1999 .................. 25,603,512 256 137,812 (230,026) (91,958) Issued on (i) Retirement of old common shares ............................ (25,603,512) (256) 256 -- -- (ii) Issuance of new common shares to old common shareholders ..................... 640,088 6 (6) -- -- (iii) Issuance of new common shares to extinguish old bond debt ............................. 15,362,107 154 161,481 -- 161,635 (iv) Issuance of new common shares to standby lenders ......... 2,694,841 27 24,219 -- 24,246 (v) Issuance of new common shares for rights offering ........ 17,139 -- -- -- -- (vi) Stock option compensation ........... -- -- 308 -- 308 Net loss .................................. -- -- -- (32,722) (32,722) ----------- ----------- ----------- ----------- ----------- Balance at December 31, 2000 ................. 18,714,175 $ 187 $ 324,070 $ (262,748) $ 61,509 =========== =========== =========== =========== ===========
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 45 46 COHO ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31 --------------------------------------- 1998 1999 2000 --------- --------- --------- Cash flows from operating activities Net loss .......................................................... $(203,346) $ (30,715) $ (32,722) Adjustments to reconcile net loss to net cash provided by operating activities: Depletion and depreciation ........................................ 28,135 13,702 15,316 Writedown of crude oil and natural gas properties ................. 188,000 5,433 3,027 Deferred income taxes ............................................. (18,488) -- -- Extraordinary item - loss on extinguishment of debt ............... -- -- 4,428 Standby loan interest ............................................. -- -- 10,090 Standby loan interest related to embedded derivative .............. -- -- 15,163 Amortization of debt issue costs and other ........................ 1,756 679 6,305 Changes in: Cash in escrow .................................................... (1,505) 1,427 (964) Accounts receivable ............................................... (1,150) (1,194) (1,622) Other assets ...................................................... (628) (454) 945 Accounts payable and accrued liabilities .......................... 7,917 25,981 (10,065) --------- --------- --------- Net cash provided by operating activities ............................ 691 14,859 9,901 --------- --------- --------- Cash flows from investing activities Property and equipment ............................................ (70,143) (6,349) (25,272) Changes in accounts payable and accrued liabilities related to exploration and development ..................................... (2,986) (1,186) 2,685 Proceeds on sale of property and equipment ........................ 61,452 -- -- --------- --------- --------- Net cash used in investing activities ................................ (11,677) (7,535) (22,587) --------- --------- --------- Cash flows from financing activities Increase in long-term debt ........................................ 76,113 4,600 255,000 Debt issuance costs ............................................... -- -- (9,732) Debt extinguishment costs ......................................... -- -- (2,126) Repayment of long-term debt ....................................... (62,043) (20) (242,600) --------- --------- --------- Net cash provided by financing activities ............................ 14,070 4,580 542 --------- --------- --------- Net increase (decrease) in cash and cash equivalents ................. 3,084 11,904 (12,144) Cash and cash equivalents at beginning of year ....................... 3,817 6,901 18,805 --------- --------- --------- Cash and cash equivalents at end of year ............................. $ 6,901 $ 18,805 $ 6,661 ========= ========= ========= Cash paid (received) during the period for: Interest .......................................................... $ 28,426 $ 8,936 $ 33,193 Income taxes ...................................................... $ (256) $ 33 $ -- Reorganization costs (including prepayments) ...................... $ -- $ 3,352 $ 7,501 Reorganization costs (interest income) ............................ $ -- $ (210) $ (260)
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 46 47 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000 (TABULAR AMOUNTS ARE IN THOUSANDS OF DOLLARS EXCEPT WHERE NOTED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization Coho Energy, Inc. ("CEI") was incorporated in June 1993 as a Texas corporation and conducts a majority of its operations through its subsidiary, Coho Resources, Inc. ("CRI"), and its subsidiaries (collectively the "Company"). Principles of Presentation These consolidated financial statements have been prepared in conformity with generally accepted accounting principles as presently established in the United States and include the accounts of CEI as successor to CRI, and its subsidiaries. All significant intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the prior year statements to conform with the current year presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Substantially all of the Company's exploration, development and production activities are conducted in the United States and Tunisia jointly with others and, accordingly, the financial statements reflect only the Company's proportionate interest in such activities. Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include cash and highly liquid debt instruments purchased with an original maturity of three months or less. Cash in Escrow Substantially all of the cash at December 31, 2000 was held in escrow pursuant to a drilling contract between the Company and a drilling contractor. Such funds will be disbursed to the drilling contractor upon completion of services. Accounts Receivable The Company performs ongoing reviews with respect to the collectibility of accounts receivable and maintains an allowance for doubtful accounts receivable ($885,000 and $675,000 at December 31, 1999 and 2000, respectively) based on expected collectibility. Crude Oil and Natural Gas Properties The Company's crude oil and natural gas producing activities, substantially all of which are in the United States, are accounted for using the full cost method of accounting. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition of crude oil and natural gas properties and with the exploration for and development of crude oil and natural gas reserves, including related gathering facilities. Proceeds from disposition of crude oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss recognized unless such dispositions involve a significant alteration in the depletion rate in which case the gain or loss is recognized. 47 48 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Depletion of crude oil and natural gas properties is provided using the equivalent unit-of-production method based upon estimates of proved crude oil and natural gas reserves and production which are converted to a common unit of measure based upon their relative energy content. Unproved crude oil and natural gas properties are not amortized, but are individually assessed for impairment. The costs of any impaired properties are transferred to the balance of crude oil and natural gas properties being depleted. Estimated future site restoration and abandonment costs are charged to earnings at the rate of depletion of proved crude oil and natural gas reserves and are included in accumulated depletion and depreciation. In accordance with the full cost method of accounting, the net capitalized costs of crude oil and natural gas properties as well as estimated future development, site restoration and abandonment costs are not to exceed their related estimated future net revenues discounted at 10%, net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. Impairment of Long-Lived Assets During 1996, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived-Assets To Be Disposed Of." The Company has no long-lived assets which are subject to the impairment test requirements of SFAS No. 121. The Company's only long-lived assets are oil and gas properties which are subject to the full cost ceiling test in accordance with the full cost method of accounting, as discussed above. Other Assets Other assets generally include deferred financing charges which are amortized over the term of the related financing under the straight-line method. At December 31, 2000, the Company had unamortized deferred financing charges associated with the new credit facility and standby loan agreement of $5.2 million and $24.1 million, respectively. Stock-Based Compensation SFAS No. 123, "Accounting for Stock-Based Compensation," encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to continue to apply Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations to account for stock-based compensation. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at earliest of the date of the grant or the first date the exercise price can be determined over the exercise price an employee must pay to acquire the stock. Earnings Per Common Share The Company accounts for earnings per share ("EPS") in accordance with SFAS No. 128, "Earnings Per Share." Under SFAS No. 128, no dilution for any potentially dilutive securities is included for basic EPS. EPS have been calculated based on the weighted average number of shares outstanding for the years ended 1998, 1999 and 2000 of 640,088, 640,088 and 14,266,336, respectively. Diluted EPS have been calculated based on the weighted average number of shares outstanding (including common shares plus, when their effect is dilutive, common stock equivalents consisting of stock options and warrants) for the years ended 1998, 1999 and 2000 of 640,088, 640,088 and 14,266,336, respectively. In 1998, 1999 and 2000, conversion of stock options and warrants would have been antidilutive and, therefore, was not considered in diluted EPS. On March 31, 2000, pursuant to the Plan of Reorganization, old shareholders of the Company's common stock received one share of the Company's new common stock for each forty shares of the Company's old common stock. All per-share amounts have been restated based on the new number of shares outstanding subsequent to the issuance of new shares. See note 2 for further discussion on the dilution of current equity interests. 48 49 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Income Taxes The Company accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Hedging Activities and Other Derivative Instruments Periodically, the Company enters into certain arrangements that fix a minimum and maximum price range in order to fix the price on a portion of its crude oil and natural gas production. Changes in the market value of crude oil and natural gas futures contracts are reported as an adjustment to revenues in the period in which the hedged production is sold. Any gain or loss on our crude oil hedging transactions is determined as the difference between the contract price and the average closing price for West Texas Intermediate crude oil on the New York Mercantile Exchange for the contract period. Any gain or loss on our natural gas hedging transactions is determined as the difference between the contract price and the New York Mercantile Exchange Henry Hub settlement price the next to last business day of the contract period. The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" effective January 1, 2001. The Statement will require the Company to recognize all derivative instruments (including certain derivative instruments embedded in other contracts) on the balance sheet as either an asset or liability based on fair value on January 1, 2001. Subsequent changes in fair value for the effective portion of derivatives qualifying as hedges will be recognized in other comprehensive income until the hedged item is recognized in earnings, at which time changes in fair value previously recognized in other comprehensive income will be reclassified to earnings. Subsequent changes in fair value for the ineffective portion of derivatives qualifying as hedges and for derivatives that are not hedges must be adjusted to fair value through earnings. The Company's hedge arrangements, as discussed above, qualify as cash flow hedges under SFAS No. 133. The estimated fair value of these hedge arrangements represented a net liability of approximately $5.8 million at December 31, 2000, which will be recorded on the balance sheet effective January 1, 2001, with an offsetting amount in accumulated other comprehensive loss. The Company has entered into certain lease agreements in Laurel, Mississippi, which contain provisions for lease payments which are to be calculated based on crude oil prices. These arrangements are considered to contain embedded derivatives under SFAS No. 133. The estimated fair value of these embedded derivatives represented a net liability of approximately $300,000 at December 31, 2000, which will be recorded on the balance sheet, effective January 1, 2001, with an offsetting amount in accumulated effect of an accounting change. The standby loan agreement, as discussed above under "Credit Facilities", contains an additional semiannual interest feature which is calculated based on the actual price the Company receives for its oil and gas production. The additional interest feature of the standby loan agreement is considered an embedded derivative under SFAS No. 133. Based on the Company's current fair valuation method, as discussed further in "Item 7A - Quantitative and Qualitative Disclosure about Market Risk", adoption of SFAS No. 133 on January 1, 2001 will result in a decrease in the existing liability at December 31, 2000 of approximately $5.5 million, with an offsetting amount to accumulated effect of an accounting change. However, due to the complexity of this embedded derivative instrument, the Company is still evaluating its method of determining fair value. Revenue Recognition Policy Revenues generally are recorded when products have been delivered and services have been performed. 49 50 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Environmental Expenditures Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures which improve the condition of a property as compared to the condition when originally constructed or acquired or prevent environmental contamination are capitalized. Expenditures which relate to an existing condition caused by past operations, and do not contribute to future operations, are expensed. The Company accrues remediation costs when environmental assessments and/or remedial efforts are probable and the cost can be reasonably estimated. Business Segments In June 1997, the Financial Accounting Standards Board issued SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information", which requires information to be reported in segments. The Company currently operates in a single reportable segment; therefore, no additional disclosure is required. 2. REORGANIZATION UNDER BANKRUPTCY PROCEEDINGS On August 23, 1999 (the "Petition Date"), the Company and its wholly-owned subsidiaries, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production Company and Interstate Natural Gas Company, filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code (the "Chapter 11 filing") in the U.S. District Court for the Northern District of Texas (the "Bankruptcy Court"). On November 30, 1999, the Company filed a plan of reorganization and subsequently filed an amended plan of reorganization on February 14, 2000 (the "Plan of Reorganization"). On March 20, 2000, the Bankruptcy Court entered an order confirming the Plan of Reorganization and on March 31, 2000, the Plan of Reorganization was consummated and the Company emerged from bankruptcy. Prior to March 31, 2000, the effective date of the Plan of Reorganization, the Company had 25,603,512 shares of old common stock issued and outstanding. Old shareholders received shares representing 4% of new common stock on a basis of one share of new common stock for 40 shares of old common stock as of the effective date without giving effect to dilution from shares issued in connection with the standby loan or shares issued under the rights offering discussed below. Additionally, shareholders as of February 7, 2000, are eligible to receive their pro rata share of 20% of any proceeds available from the lawsuit filed against five affiliates of Hicks, Muse, Tate & Furst (the "Hicks Muse Lawsuit") after fees and expenses and 40% of any proceeds of the disposition of the Company's interest in, or the assets of, Coho Anaguid, Inc. Coho Anaguid owns a 45.83% interest in a permit in Tunisia, North Africa. At March 31, 2000, the Company charged 40% of the carrying value of Coho Anaguid, Inc., approximately $1.1 million, to reorganization expense. On May 2, 2000, the Company distributed stock rights to the holders of its old common stock as of the record date of March 6, 2000, to purchase up to an aggregate of 8,663,846 shares of its new common stock. Each holder of old common stock received 0.338 rights for every share of old common stock held by such holder. Each right allowed a holder to buy one share of new common stock at a price of $10.40 per share. There were 14,669 rights exercised under the offering; however, pursuant to an antidilution feature which applied to shares issued in the rights offering, 1.17 shares were issued for each right exercised. Unexercised rights expired May 31, 2000. The Company received $153,000 upon completion of the offering on May 31, 2000. Proceeds from the rights offering were used to pay offering costs; however, offering costs exceeded the proceeds from the rights offering and the excess costs were charged to accrued reorganization costs. The reorganized value of the Company's assets exceeded the total of all postpetition liabilities and allowed claims; therefore, the Company did not qualify for fresh-start accounting. The Company has recorded the following transactions to effect the Company's Plan of Reorganization consummated on March 31, 2000: o The borrowing of $183.0 million under the Company's new credit facility. o The borrowing of $72.0 million under the standby loan and the issuance of 2,694,841 shares of new common stock as debt issuance costs at a diluted reorganization value of approximately $9.00 per share for a total of $24.2 million. The diluted reorganization value of $9.00 per share was caused by the old bondholders 50 51 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) accepting a dilution in the value of their new common stock to obtain the standby loan financing for the reorganized company. The dilution is a result of the issuances of additional shares to the standby lenders. o Repayment of borrowings outstanding under the old bank credit facility together with accrued interest and reasonable fees totaling $260.2 million, resulting in a $303,000 loss on extinguishment of debt. o Conversion of the old bonds into 15,362,107 shares of new common stock, representing 96% of the new common stock without giving effect to dilution from shares issued in connection with the standby loan or shares issued under the rights offering, at a reorganization value of approximately $10.52 per share resulting in a $4.1 million loss on extinguishment of debt. Although the old bonds were paid no more than in full, the Company did realize a loss on extinguishment of debt because the Company's carrying value of the old bonds was less than the allowed claim, primarily due to unamortized debt issuance costs. o Provision of $1.6 million to allow for settlement of disputed claims. o Payment of all allowed senior secured claims and all other allowed claims less than $1,000, aggregating approximately $500,000. All other allowed claims will be or have been paid in full as follows: o Substantially all unsecured claims were paid in full in four quarterly installments with the final installment made on January 2, 2001. o Priority tax claims will receive five-year, interest-bearing promissory notes. o Payment of costs associated with the bankruptcy were paid upon court approval during the six months following the consummation of the Plan of Reorganization. In conjunction with its Plan of Reorganization, the Company terminated 19 corporate office employees and seven officers in April 2000. Costs of $438,000 associated with termination benefits for the 19 corporate office employees were accrued as of March 31, 2000 and charged to reorganization expense and subsequently paid in the quarter ended June 30, 2000. Additionally, the Company rejected all of its officer employment agreements and officer severance agreements in connection with the Plan of Reorganization, including the seven terminated officers. The Company has negotiated settlement agreements related to the claims for these rejected contracts. Approximately $3.0 million was accrued and charged to reorganization expense for these claims settlements which were paid during the nine months following the consummation of the Plan of Reorganization. The Company's Plan of Reorganization provided for a retention plan under which employees were provided with additional incentives to continue their employment with the Company throughout 2000. The amount of cash awards paid under the retention plan was $1.2 million, of which 33% was paid upon the effective date of the Plan of Reorganization and 67% was paid on January 1, 2001. Costs of $419,000 payable upon the effective date of the Plan of Reorganization were accrued and charged to reorganization expense at March 31, 2000 and subsequently paid on April 14, 2000. Payments of approximately $815,000, which were paid January 1, 2001, were amortized monthly over the subsequent nine-month period and charged to reorganization expense. 3. PROPERTY AND EQUIPMENT
December 31 ------------------------ 1999 2000 --------- --------- Crude oil and natural gas leases and rights including exploration, development and equipment thereon, at cost ....................... $ 684,896 $ 709,118 Accumulated depletion and depreciation ............................... (373,108) (391,451) --------- --------- $ 311,788 $ 317,667 ========= =========
Overhead expenditures directly associated with exploration for and development of crude oil and natural gas reserves have been capitalized in accordance with the accounting policies of the Company. Such charges totaled $5,749,000, $0, and $765,000 in 1998, 1999 and 2000, respectively. Due to the cessation of exploration and development of crude oil and natural gas reserves in 1998, all overhead expenditures during 1999 and the first quarter 51 52 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) of 2000 were charged to general and administrative expense. Subsequent to the first quarter of 2000, the Company has increased development work, therefore related overhead and expenditures were capitalized for the remainder of the year. During 1998, 1999 and 2000, the Company did not capitalize any interest or other financing charges on funds borrowed to finance unproved properties or major development projects. Unproved crude oil and natural gas properties totaling $56,296,000 and $30,603,000 at December 31, 1999 and 2000, respectively, have been excluded from costs subject to depletion. These costs are anticipated to be included in costs subject to depletion within the next five years. Depletion and depreciation expense per equivalent barrel of production was $4.38, $3.63 and $3.94 in 1998, 1999 and 2000, respectively. During 2000, $25.7 million of unproved costs, previously excluded from the costs subject to depletion were included in the 2000 costs subject to depletion due to the reclassification of the related reserves from unproved to proved or abandonment of the related project. 4. LONG-TERM DEBT
December 31 ------------------------- 1999 2000 --------- ---------- Old bank group loan ..................................... $ 239,600 $ -- Old bonds ............................................... 150,000 -- New credit facility ..................................... -- 180,000 Standby loan ............................................ -- 77,358 Standby loan interest to be paid-in-kind ................ -- 4,732 Standby loan interest related to embedded derivative .... -- 15,163 Promissory notes ........................................ -- 5,195 Other ................................................... 3 1,000 --------- --------- 389,603 283,448 Unamortized original issue discount on old bonds ........ (918) -- Current maturities of long-term debt .................... (388,685) (1,036) --------- --------- $ -- $ 282,412 ========= =========
The Company and some of its subsidiaries were parties to an old bank group loan agreement. Borrowings outstanding under the old bank group loan together with accrued interest and fees totaling $260.2 million were paid on March 31, 2000. The Company obtained the funds necessary for the payment of the old bank group loan through the combination of borrowings under its new senior revolving credit facility, borrowings under the standby loan and from cash accumulated during the bankruptcy. Additionally, the Company owed approximately $162 million of principal and accrued interest under its old bonds. Under the Plan of Reorganization, these old bonds and accrued interest were converted into 15,362,107 shares of new common stock. New Credit Facility The new senior revolving credit facility was obtained from a syndicate of lenders led by The Chase Manhattan Bank, as agent for the new lenders, and has a principal amount of up to $250 million. The new credit facility limits advances to the amount of the borrowing base, which is currently at $205 million. The borrowing base is the loan value assigned to the proved reserves attributable to the Company's oil and gas properties. The new credit facility is subject to semiannual borrowing base redeterminations each April 1 and October 1, based on the Company's reserve reports, and will be made at the sole discretion of the lenders. The Company or Chase may each request one additional borrowing base redetermination during any calendar year. 52 53 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Interest on advances under the new credit facility will be payable on the earlier of the expiration of any interest period under the new credit facility or quarterly. Amounts outstanding under the new credit facility will accrue interest at the Company's option at either the Eurodollar rate, which is the annual interest rate equal to the London Interbank Offered Rate for deposits in United States dollars that is determined by reference to the Telerate Service or offered to Chase plus an applicable margin (currently 3%), or the prime rate, which is the floating annual interest rate established by Chase from time to time as its prime rate of interest plus an applicable margin (currently 2%). All outstanding advances under the new credit facility are due and payable on March 31, 2003. The new credit facility has been secured by substantially all of the Company's assets. The new credit agreement contains financial and other covenants including: o maintenance of required ratios of cash flow to interest expense paid or payable in cash (2 to 1 for the average of the last four consecutive quarters most recently ended December 31, 2000, gradually increasing to 3 to 1 for quarters ending after January 1, 2002), senior debt to cash flow required (not to exceed 5 to 1 for the average of the last four consecutive quarters ended December 31, 2000, gradually decreasing to 3.5 to 1 for any quarter ending after January 1, 2002), and current assets (including unused borrowing base) to current liabilities required (throughout the term of the credit agreement, to be 1 to 1 as of the end of each quarter); o restrictions on the payment of dividends; and o limitations on the incurrence of additional indebtedness, the creation of liens and the incurrence of capital expenditures. The lenders received $5.8 million of closing fees in addition to expense reimbursements. Standby Loan The standby loan was made under a senior subordinated note facility under which the Company issued $72 million of senior subordinated notes to PPM America, Inc., Appaloosa Management, L.P., Oaktree Capital Management, L.L.C., Pacholder Associates, Inc. and their respective assignees. The Company's rights and responsibilities and those of the standby lenders are governed by a standby loan agreement which was executed and delivered on March 31, 2000. Debt under the standby loan agreement is evidenced by notes maturing March 31, 2007 and bearing interest at a minimum annual rate of 15% and payable in cash semiannually. After March 31, 2001, additional semiannual interest payments will be payable in an amount equal to 1/2% for every $0.25 that the "actual price" for the Company's oil and gas production exceeds $15 per barrel of oil equivalent during the applicable semiannual interest period, up to a maximum of 10% additional interest per year. The "actual price" for the Company's oil and gas production is the weighted average price received by the Company for all its oil and gas production, including hedged and unhedged production, net of hedging costs, in dollars per barrel of oil equivalent using a 6:1 conversion ratio for natural gas. The actual price will be calculated over a six-month measurement period ending on the date two months before the applicable interest payment date. Additionally, upon an event of default occurring under the standby loan, interest will be payable in cash, unless otherwise required to be paid-in-kind, at a rate equal to 2% per year over the applicable interest rate. Interest payments under the standby loan may be paid-in-kind subject to the requirements of the intercreditor arrangement between the standby lenders and the lenders under the new credit agreement. "Paid-in-kind" refers to the payment of interest owed under the standby loan by increasing the amount of principal outstanding through the issuance of additional standby loan notes, rather than paying the interest in cash. The standby loan semi-annual interest payment was paid-in-kind when due on September 29, 2000 and has been reflected as an increase in long-term debt. In addition, accrued interest of $4.7 million at December 31, 2000 has been classified as long-term debt as the March 31, 2001 interest payment will be paid-in-kind. The additional semiannual interest payment feature of the standby loan agreement based on the actual price received for the Company's oil and gas production, as discussed above, is considered an embedded derivative instrument. The additional interest cost associated with this embedded derivative instrument is calculated at the origination of each loan and at each future balance sheet date. The aggregate amount of the additional interest payments on the original $72 million standby loan was estimated at its inception date, using the future crude oil and natural gas price curves as of such date. These estimated additional interest payments were added to interest payments 53 54 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) due based on the minimum annual rate at 15% to determine an effective interest rate of 18.04% for the term of the original $72 million standby loan. In addition, the same procedures were applied to the standby loan of $5.4 million issued on September 29, 2000 to determine an effective rate of 23.92% for the term of this loan. The aggregate amount of the additional interest payments was redetermined at December 31, 2000 using the then current future crude oil and natural gas price curves. The increase of $15.2 million in the aggregate amount of additional interest payments based on the December 31, 2000 price curves as compared to the aggregate amount of additional interest payments based on the price curves at the inception date of each loan was reflected as an increase in the standby loan debt and a charge to interest expense during 2000. The interest expense may continue to have significant volatility from period to period based on changes in future price curves from period to period. For additional discussion on volatility of interest expense, see note 1 -- "Hedging Activities and Other Derivative Instruments". Payment of the standby loan notes will be expressly subordinate to payments in full in cash of all obligations arising in connection with the new credit facility. After the initial 12-month period, cash interest payments may be made only to the extent by which EBITDA, or earnings before interest, tax, depreciation and amortization expense, on a trailing four-quarter basis exceeds $65 million. The new credit agreement also prohibits the Company from making any cash interest payments on the standby loan indebtedness if the outstanding indebtedness under both the new credit facility and the standby loan exceeds 3.75 times the EBITDA for the trailing four quarters. The Company does not currently meet the requirements to make cash interest payments on the standby loan indebtedness. The Company may prepay the standby loan notes at the face amount, in whole or in part, in minimum denominations of $1,000,000, plus either a standard make-whole payment at 300 basis points over the "treasury rate" for the first four years, or beginning in the fifth year, a prepayment fee of 7.5% of the principal amount being prepaid; in the sixth year, a prepayment fee of 3.75% of the principal amount being prepaid; and after the sixth year there is no prepayment fee. The "treasury rate" is the yield of U.S. Treasury securities with a term equal to the then-remaining term of the standby loan notes that has become publicly available on the third business day before the date fixed for repayment. When the standby loan notes were issued on March 31, 2000, the standby lenders became entitled to 14.4% of the Company's fully diluted new common stock valued at approximately $24.2 million. The shares were registered with the Securities and Exchange Commission in connection with the rights offering and were issued on June 1, 2000. The shares of new common stock issued to the standby lenders were in addition to the shares of new common stock issued to holders of the old bonds, to the Company's shareholders prior to reorganization and to persons participating in the rights offering. Additionally, the standby lenders received closing fees of approximately $2.5 million as well as expense reimbursements. Promissory Notes Claims for tax, penalty and interest were filed against the Company by the State of Louisiana and the State of Mississippi. The Company currently has appeals pending with both taxing authorities for portions of the filed claims. The Company has accrued an estimated $5.2 million for settlement of these priority tax claims, of which $4.2 million is included in long term debt and approximately $1 million is included in current portion of long-term debt. Five-year, interest-bearing promissory notes will be issued to satisfy these claims. Other The Company has settled the claims of Chevron Corp. and Chevron USA for indemnification of environmental liabilities in the Brookhaven field. The terms of this settlement require the Company to fund $2.5 million over the next two years to partially finance the implementation of a remediation plan. The Company paid $1.0 million in June 2000, $500,000 was paid on January 2, 2001 and is included in current liabilities at December 31, 2000 and the remaining $1.0 million, due on January 1, 2002, is included in long-term debt. 54 55 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Debt Repayments Based on the balances outstanding under the new credit facility, the standby loan agreement, the promissory notes, and the Chevron settlement, estimated aggregate principal repayments for each of the next five years are as follows: 2001 - $1,052,000, 2002 - $2,036,000, 2003 - $181,036,000, 2004 - $1,036,000, 2005 - $1,036,000, and $77,357,000 thereafter. 5. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental noncash financing activities for the year ended December 31, 2000 are as follows: 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 =========
6. INCOME TAXES Deferred income taxes are recorded based upon differences between financial statement and income tax basis of assets and liabilities. The tax effects of these differences which give rise to deferred income tax assets and liabilities at December 31, 1999 and 2000, were as follows:
1999 2000 -------- -------- DEFERRED TAX ASSETS Net operating loss carryforwards ......................................... $ 46,614 $ 45,487 Property and equipment, due to differences in depletion, depreciation, amortization and writedowns .......................................... 20,822 13,815 Alternative minimum tax credit carryforwards ............................. 1,466 1,466 Employee benefits ........................................................ 61 25 Reorganization costs ..................................................... 1,062 2,103 Other .................................................................... 502 6,449 -------- -------- Total gross deferred tax assets .......................................... 70,527 69,345 Less valuation allowance ................................................. (70,527) (69,345) -------- -------- Net deferred tax assets .................................................. -- -- -------- -------- DEFERRED TAX LIABILITIES Property and equipment, due to differences in depletion, depreciation, amortization and writedowns .......................................... -- -- -------- -------- NET DEFERRED TAX LIABILITY ................................................... $ -- $ -- ======== ========
55 56 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The valuation allowance for deferred tax assets as of December 31, 1999 and 2000 includes $248,314 and $192,665, respectively, related to Canadian deferred tax assets. To determine the amount of net deferred tax liability it is assumed no future capital expenditures will be incurred other than the estimated expenditures to develop the Company's proved undeveloped reserves. The following table reconciles the differences between recorded income tax expense and the expected income tax expense obtained by applying the basic tax rate to earnings (loss) before income taxes:
1998 1999 2000 --------- --------- --------- Earnings (loss) before income taxes $(217,729) $ (30,742) $ (32,722) ========= ========= ========= Expected income tax expense (recovery) (statutory rate - 34%) $ (74,028) $ (10,452) $ (11,125) State taxes - deferred (6,242) (913) (611) Federal benefit of state taxes 2,122 310 208 Permanent differences -- 367 9 Expiring NOLs 1,043 2,390 12,724 Change in valuation allowance 57,838 8,095 (1,182) Other 4,884 177 (23) --------- --------- --------- $ (14,383) $ (26) $ -- ========= ========= =========
At December 31, 2000, the Company had the following income tax carryforwards available to reduce future years' income for tax purposes:
Expires Amount --------- -------- Net operating loss carryforwards for federal income tax purposes 2001 $ 0 2002 0 2003 0 2004 0 2005-2020 117,949 -------- $117,949 ======== Operating loss carryforwards for Canadian income tax purposes 2001-2006 $ 507 ======== Operating loss carryforwards for federal alternative minimum tax purposes 2009-2020 $101,979 ======== Federal alternative minimum tax credit carryforwards -- $ 1,466 ======== Operating loss carryforwards for Mississippi income tax purposes 2010-2014 $105,743 ======== Operating loss carryforwards for Oklahoma income tax purposes 2012-2013 $ 50,086 ========
7. DISPOSITION On December 2, 1998, the Company sold its natural gas assets, including its natural gas properties and the related gas gathering systems, located in Monroe, Louisiana to an unaffiliated third party for net proceeds of approximately $61.5 million. The proved reserves attributable to such natural gas properties were approximately 94 billion cubic feet of natural gas and represented approximately 14% of the Company's year-end 1997 proved reserves. 8. SHAREHOLDERS' EQUITY To effect the Company's Plan of Reorganization, the Company: o issued new common stock to old shareholders on a basis of one share of new common stock for 40 shares of old common stock; 56 57 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) o converted the old bonds into 15,362,107 shares of new common stock; o issued 2,694,841 shares of new common stock as debt issuance costs under the standby loan agreement; and o issued 17,139 shares of new common stock pursuant to a rights offering. See note 2 for further discussion on the conversion of old common stock and the issuance of new common stock. 9. STOCK-BASED COMPENSATION Prior to the consummation of the Plan of Reorganization, options to purchase the Company's common stock were granted to officers, directors and key employees pursuant to the Company's 1993 Stock Option Plan and 1993 Non Employee Director Stock Option Plan, or assumed from the reorganization of the Company's subsidiaries in 1993. The stock option plans provided for the issuance of five-year options with a three-year vesting period and a grant price equal to or above market value. Some exceptions were made to provide immediate or shortened vesting periods as approved by the Company's board of directors. All options outstanding or available for grant prior to the consummation of the Plan of Reorganization were terminated according to the Plan of Reorganization. Option shares and values for 1998 and 1999 have not been restated to reflect the conversion of old common stock to new common stock (see note 2). Subsequent to the consummation of the Plan of Reorganization, the Company has granted options to purchase the Company's common stock to certain officers and directors of the Company. The options granted to the Company's officers vest over a two-year period and the options granted to the Company's directors are immediately vested on the grant date. A summary of the status of the Company's stock option plans at December 31, 1998, 1999 and 2000 and changes during the years then ended follows:
1998 1999 2000 ---------------------- ---------------------- ----------------------- WTD AVG WTD AVG WTD AVG SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE ---------- -------- ---------- -------- ---------- -------- Outstanding at January 1 2,823,815 $6.96 2,631,260 $6.98 2,238,101 7.13 Granted 14,000 6.88 -- -- 1,031,448 8.10 Exercised -- -- -- -- -- -- Canceled (75,000) 8.90 (30,000) 8.42 (2,238,101) 7.13 Expired (131,555) 5.40 (363,159) 5.97 -- -- ---------- ----- ---------- ----- ---------- ----- Outstanding at December 31 2,631,260 6.98 2,238,101 7.13 1,031,448 8.10 ---------- ----- ---------- ----- ---------- ----- Exercisable at December 31 2,310,438 6.60 2,112,445 6.94 295,362 7.88 Available for grant at December 31 189,919 437,668 0
Significant option groups outstanding at December 31, 2000 and related weighted average price and life information follows:
Options Options Wtd Avg Remaining Grant Date Outstanding Exercisable Exercise Price Life (Years) - ---------- ----------- ----------- -------------- ------------ April 1, 2000 981,448 245,362 $ 8.19 (a) August 17, 2000 50,000 50,000 $6.375 (a)
(a) Options expire one year after termination of participant. 57 58 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The weighted average fair value of options at the date of grant for options granted during 1998 and 2000 was $3.12 and $4.42 per option, respectively. The fair value of options at date of grant was estimated using the Black-Scholes model with the following weighted average assumptions:
1998 1999 2000 ------- ------ ------ Expected life (years) 5 -- 5 Interest rate 5.67% -- 6.305% Volatility 42.01% -- 42.00% Dividend yield -- -- --
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:
1998(c) 1999 (c) 2000 ---------- -------- -------- Net loss As reported ....................... $ (203,346) $(30,715) $(32,722) Pro forma ......................... $ (204,108) $(31,321) $(34,281) Basic loss per share As reported ....................... $ (317.68) $ (47.99) $ (2.29) Pro forma ......................... $ (318.88) $ (48.93) $ (2.40) Diluted loss per share As reported ....................... $ (317.68) $ (47.99) $ (2.29) Pro forma ......................... $ (318.88) $ (48.93) $ (2.40)
(c) Per share amounts restated for conversion of old common stock to new common stock (see note 2) 10. COMMITMENTS AND CONTINGENCIES (a) Like other crude oil and natural gas producers, the Company's operations are subject to extensive and rapidly changing federal and state environmental regulations governing emissions into the atmosphere, waste water discharges and solid and hazardous waste management activities. At December 31, 2000, the Company has accrued approximately $584,000 related to such costs, of which $64,000 is included in current liabilities and $520,000 is included in contingent liabilities. At this time, the Company does not believe that any potential liability, in excess of amounts already provided for, would have a significant effect on the Company's financial position or the results of operations. (b) The Company's operations are subject to site restoration and abandonment costs. The Company's policy is to make a provision for future site restoration charges on a unit-of-production basis. Total future site restoration costs are estimated to be $6,000,000. A total of $3.1 million has been included in depletion and depreciation expense with respect to such costs as of December 31, 2000. (c) On May 27, 1999, the Company filed a lawsuit against five affiliates of Hicks, Muse, Tate & Furst. The lawsuit alleges (1) breach of the written contract terminated by HM4 Coho L.P. ("HM4"), a limited partnership formed by Hicks Muse on behalf of the Hicks, Muse, Tate & Furst Equity Fund IV, in December 1998, (2) breach of the oral agreements reached with HM4 on the restructured transaction in February 1999 and (3) promissory estoppel. In the lawsuit, the Company seeks monetary damages of approximately $300 million. Discovery is substantially complete and both sides have filed motions for summary judgement, which were heard during January 2001. The Court has denied the Company's motion for summary judgment, and has granted, in part, and denied, in part, Hicks, Muse's motion. Based on these orders, it appears that the Company will be able to go to trial on a claim for breach of contract that has an actual damages of up to $165 million. The Company believes that the lawsuit has merit and that the actions of HM4 in December 1998 and February 1999 were the primary cause of the Company's liquidity crisis; however, there can be no assurance as to the outcome of this litigation. (d) On June 9, 2000, Energy Investment Partnership No. 1, an affiliate of Hicks, Muse, Tate & Furst, filed a lawsuit against certain former officers of the Company alleging, among other things, such officers made or caused to be made false and misleading statements as to the proved oil and gas reserves purportedly owned by the Company. The plaintiffs are asking for compensatory damages of approximately $15 million plus punitive damages. 58 59 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Pursuant to the Company's bylaws, the Company may be required to indemnify such former officers against damages incurred by them as a result of the lawsuit not otherwise covered by the Company's directors' and officers' liability insurance policy. The judge has dismissed certain claims and the case is set for trial in the spring of 2002. The Company believes the lawsuit is without merit and does not expect the outcome of the lawsuit to have a material adverse effect on the Company's financial position or results of operations. (e) During June 1999, the Company extended its Anaguid permit in Tunisia, North Africa through December 2001. The Company has a commitment to drill two additional wells during this two-year period. See note 15 -- "Subsequent Events" for further discussion regarding the Company's operations in Tunisia, North Africa. (f) The Company has leased (i) 26,751 square feet of office space in Dallas, Texas under a non-cancellable lease extending through December 2005, with a one time cancellation option during September 2003, (ii) 10,000 square feet of office space in Ratliff City, Oklahoma and (iii) surface leases in Laurel, Mississippi with expiration dates extending through the year 2018. Rental expense totaled $1,668,000, $1,798,000 and $1,394,000 in 1998, 1999 and 2000, respectively. Minimum rentals payable under these leases for each of the next five years are as follows: 2001 - $1,192,000; 2002 - $1,192,000; 2003 - $1,173,000; 2004 - $1,172,000 and 2005 -$1,172,000. Total rentals payable over the remaining terms of the leases are $4,180,000. (g) The Company has entered into employment agreements with certain of its officers. In addition to base salary and participation in employee benefit plans offered by the Company, these employment agreements generally provide for a severance payment in an amount equal to two times the rate of base annual compensation of the officer in the event there is a change of control or in the event the officer's employment is terminated for other than cause. The officers' aggregate annual compensation covered under such employment agreements is approximately $800,000. (h) The Company has entered into executive stay agreements with certain key employees which are designed to encourage these key employees to continue to carry out their duties with the Company in the event of a change in control of the Company. If the employee, subsequent to a change in control, continues to be employed by the Company for a period of not less than 180 days or if the employee's employment is terminated for other than cause, these stay agreements generally provide for a payment in an amount equal to 1.0 times the employees annual salary. The annual salary paid to the key employees covered under such severance agreements aggregates approximately $406,000. 11. FINANCIAL INSTRUMENTS AND CREDIT RISK CONCENTRATIONS Financial instruments which are potentially subject to concentrations of credit risk consist principally of cash, cash equivalents and accounts receivable. Cash and cash equivalents are placed with high credit quality financial institutions to minimize risk. The carrying amounts of these instruments approximate fair value because of their short maturities. The Company has entered into certain financial arrangements which act as a hedge against price fluctuations in future crude oil and natural gas production. Included in operating revenues are gains (losses) of $488,000, $0 and $(10,401,000) for 1998, 1999 and 2000, respectively, resulting from these hedging programs. At December 31, 1999 and 2000, the Company had no deferred hedging gains or losses. As of December 31, 2000, the Company had $5,078,000 in unrealized losses. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Results of Operations" for discussion on hedging arrangements. Fair values of the Company's financial instruments are estimated through a combination of management's estimates and by reference to quoted prices from market sources and financial institutions, if available. As of December 31, 2000, the fair market value of the Company's standby loan notes was $87.0 million compared to the related carrying value of $92.5 million. The fair value of the old bonds at December 31, 1999 was $83 million compared to the related carrying value of $149 million. The carrying value of the new credit facility and old bank group loan agreement approximated fair market value at December 31, 2000 and December 31, 1999 since the applicable interest rate approximated the market rate. 59 60 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) During 1998, three purchasers of our crude oil and natural gas, EOTT Energy Corp. ("EOTT"), Amoco Production Company, and Mid Louisiana Marketing Company, accounted for 42%, 28% and 14%, respectively, of the Company's revenue. During 1999, EOTT and Amoco Production Company accounted for 39% and 41%, respectively, of the Company's revenue. During 2000, EOTT and Amoco Production Company accounted for 41% and 29%, respectively, of the Company's revenue. Included in accounts receivable is $1,965,000 and $114,000 and $250,000 from these customers at December 31, 1998, 1999 and 2000, respectively. In October 2000, we began selling our crude oil that had been previously sold to Amoco, to Teppco Crude Oil, LLP and Sunoco, Inc. 12. RELATED PARTY TRANSACTIONS (a) In 1990, the Company made a non-interest bearing loan in the amount of $205,000 to Jeffrey Clarke, the Company's former President and Chief Executive Officer, to assist him in the purchase of a house in Dallas. The Company has entered into an executive employment severance agreement with Mr. Clarke in which he will receive a forbearance of the loan from the Company in exchange for his assistance in the Hicks Muse lawsuit. The loan will be forgiven on the date the Hicks Muse lawsuit is settled or otherwise completed. At March 31, 2000, the Company provided an allowance for this loan and charged reorganization expense. (b) Pursuant to an equity offering, the Company's officers and directors were precluded from selling stock for a 90-day period beginning October 3, 1997 (the "Lock Up Period"). On October 6, 1997, the Company made sole recourse, non-interest bearing loans of $622,111, payable on demand, secured by the related Company's common stock to certain officers and a director. The loans were made to provide assistance in acquiring stock upon exercise of expiring stock options during the Lock Up Period. During 1998, the Company provided an allowance for bad debt for the entire amount of such loans due to the decrease in the share price of the Company's common stock provided by such officers and directors as collateral. The Company released these parties from any claim under these loans in connection with the cancellation of contracts and the related settlement negotiations in the Plan of Reorganization. (c) Under the terms of a Financial Advisory Agreement entered into between the Company and Hicks, Muse & Co. Partners, L.P. ("HMCo"), on August 21, 1998, the Company paid HMCo $1,250,000 as compensation for HMCo's services as a financial advisor to the Company and its subsidiaries in connection with an agreement to issue common stock of the Company to HM4. John R. Muse and Lawrence D. Stuart, Jr., are each limited partners in HMCo and limited partners of a limited partner in HM4, and at the time of the payment to HMCo, were directors of the Company under an agreement with Energy Investment Partnership No. 1, L.P. On March 18, 1999, Messrs, Muse and Stuart resigned from the board of directors of the Company. (d) On March 31, 2000, the Company issued $72 million of senior subordinated notes (see note 4), of which $65.5 million were issued to the Company's major shareholders and their affiliates. In addition, participants purchasing the notes were entitled to a cash origination fee equal to 3 1/2% of the face amount of the notes purchased plus 2,694,841 shares of the Company's common stock. Share information, loan origination fees and notes purchased by the Company's major shareholders are as follows:
Loan Origination Senior Notes Common Shares Fee (in 000's) Purchased (in 000's) ------------- ---------------- -------------------- PPM America, Inc. and affiliates ............ 1,466,723 $ 1,382 $ 39,500 Appaloosa Management, L.P. and affiliates ... 587,157 $ 560 $ 16,000 Oaktree Capital Management, LLC and affiliates ................................ 374,283 $ 350 $ 10,000
In addition, during April 2000, certain officers of the Company were entitled, pursuant to their employment contracts, to participate in the senior note loans and receive the benefit of the loan origination fee and additional shares of common stock issued by purchasing senior notes at face value from Appaloosa Management, L.P. and PPM America, Inc. and affiliates. Share information, loan origination fees and senior notes purchased from the major shareholders by officers of the Company are as follows: 60 61 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Loan Origination Senior Notes Common Shares Fee (in 000's) Purchased (in 000's) ------------- ---------------- -------------------- Michael McGovern ........ 13,100 $12.5 $ 350 Gary L. Pittman ......... 6,550 $ 6.0 $ 175 Gerald E. Ruley ......... 3,743 $ 3.5 $ 100
(e) The senior subordinated notes, as discussed in (d) above, require semiannual interest payments payable in cash or, if required pursuant to the intercreditor arrangement between the standby lenders and the lenders under the new credit agreement, paid-in-kind (see note 4). On September 29, 2000, the semiannual interest payment of $5,358,000 was paid-in-kind to the holders of the senior subordinated notes, resulting in the issuance of new senior subordinated notes to certain major shareholders and officers as follows:
Senior Notes Issued (in 000's) ------------------------------ PPM America, Inc. and affiliates ............ $2,923 Appaloosa Management, L.P. and affiliates ... $1,170 Oaktree Capital Management, LLC and affiliates ................................ $ 657 Michael McGovern ............................ $ 26 Gary L. Pittman ............................. $ 13 Gerald E. Ruley ............................. $ 7
(f) On April 1, 2000, the Company entered into an agreement with Pirinate Consulting Group, LLC with respect to monthly financial advisory services to be performed by Eugene Davis for the Company for a monthly retainer of $15,000. Mr. Davis is Chairman and Chief Executive Officer of Pirinate Consulting Group, LLC and is currently a director of the Company. 13. SUPPLEMENTARY QUARTERLY FINANCIAL DATA (UNAUDITED)
First Second Third Fourth Total --------- --------- --------- --------- --------- 2000 Operating revenues ....................... $ 22,646 $ 23,858 $ 21,947 $ 21,731 $ 90,182 Operating income (loss) .................. 9,360 11,429 8,864 4,964 34,617 Net income (loss) ........................ (14,629) (2,315) (23,039) 7,261 (32,722) Basic income (loss) per share ............ $ (17.45) $ (.12) $ (1.23) $ .39 $ (2.29) Diluted income (loss) per share .......... $ (17.45) $ (.12) $ (1.23) $ .39 $ (2.29) 1999 Operating revenues ....................... $ 8,967 $ 12,161 $ 16,829 $ 19,366 $ 57,323 Operating income (loss) .................. (1,127) 428 (675) 7,454 6,080 Net loss ................................. (8,987) (10,102) (10,733) (893) (30,715) Basic loss per share (restated) .......... $ (14.04) $ (15.78) $ (16.77) $ (1.40) $ (47.99) Diluted loss per share (restated) ........ $ (14.04) $ (15.78) $ (16.77) $ (1.40) $ (47.99) 1998 Operating revenues ....................... $ 21,143 $ 18,147 $ 16,539 $ 12,930 $ 68,759 Operating income (loss) .................. (28,206) (38,306) 1,344 (119,840) (185,008) Net loss ................................. (22,301) (41,611) (7,168) (132,266) (203,346) Basic loss per share (restated) .......... $ (34.84) $ (65.01) $ (11.20) $ (206.64) $ (317.68) Diluted loss per share (restated) ........ $ (34.84) $ (65.01) $ (11.20) $ (206.64) $ (317.68)
Basic per share figures are computed based on the weighted average number of shares outstanding for each period shown. Diluted per share figures are computed based on the weighted average number of shares outstanding including common stock equivalents, consisting of stock options and warrants, when their effect is dilutive. 1998, 1999 and the first quarter of 2000 have been restated to reflect the conversion of old common stock to new common stock. 61 62 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) 14. SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS ACTIVITIES Costs Incurred Costs incurred for property acquisition, exploration and development activities were as follows:
1998 1999 2000 -------- -------- -------- Property acquisitions Proved ............................................. $ 8,432 $ -- $ 432 Unproved ........................................... 4,646 -- -- Exploration ............................................ 5,061 2,198 2,330 Development ............................................ 51,049 4,101 22,415 Other .................................................. 955 50 96 -------- -------- -------- $ 70,143 $ 6,349 $ 25,273 ======== ======== ======== Property and equipment, net of accumulated depletion ... $324,574 $311,788 $317,734 ======== ======== ========
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.
Reserve Quantities ------------------------ Oil Gas (MBbls) (MMcf) -------- -------- Estimated reserves at December 31, 1997 ............ 95,084 147,505 Revisions of previous estimates .................... (7,645) 4,459 Purchase of reserves in place ...................... 6,842 480 Sales of reserves in place ......................... -- (94,106) Extensions and discoveries ......................... 10,792 16,114 Production ......................................... (5,069 (8,124) -------- -------- Estimated reserves at December 31, 1998 ............ 100,004 66,328 Revisions of previous estimates .................... 9,718 (25,257) Purchase of reserves in place ...................... -- -- Sales of reserves in place ......................... -- -- Extensions and discoveries ......................... 734 2,175 Production ......................................... (3,343) 2,608) -------- -------- Estimated reserves at December 31, 1999 ............ 107,113 40,638 Revisions of previous estimates .................... (9,239) (11,083) Purchase of reserves in place ...................... 285 -- Sales of reserves in place ......................... (9) (26) Extensions and discoveries ......................... 1,377 1,258 Production ......................................... (3,534) (2,076) -------- -------- Estimated reserves at December 31, 2000 ............ 95,993 28,711 ======== ======== Proved developed reserves at December 31, 1998 ............................................ 66,869 48,176 1999 ............................................ 73,748 25,794 2000 ............................................ 65,832 24,453
62 63 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) Standardized Measure of Oil and Gas Reserves (unaudited) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves. The following standardized measure of discounted future net cash flows was computed in accordance with the rules and regulations of the Securities and Exchange Commission and SFAS No. 69 using year end prices and costs, and year end statutory tax rates. Royalty deductions were based on laws, regulations and contracts existing at the end of each period. No values are given to unproved properties or to probable reserves that may be recovered from proved properties. The inexactness associated with estimating reserve quantities, future production and revenue streams and future development and production expenditures, together with the assumptions applied in valuing future production, substantially diminishes the reliability of this data. The values so derived are not considered to be an estimate of fair market value. The Company therefore cautions against this use. The following tabulation reflects the Company's estimated discounted future cash flows from crude oil and natural gas production:
1998 1999 2000 ----------- ----------- ----------- Future cash inflows .......................................... $ 1,081,003 $ 2,562,981 2,597,866 Future production costs ...................................... (419,820) (642,024) (760,223) Future development costs ..................................... (112,165) (136,589) (123,636) Future income taxes .......................................... (55,008) (435,311) (419,290) ----------- ----------- ----------- Future net cash flows ........................................ 494,010 1,349,057 1,294,717 Annual discount at 10% ....................................... (224,712) (656,182) (698,428) ----------- ----------- ----------- Standardized measure of discounted future net cash flows ..... $ 269,298 $ 692,875 $ 596,289 =========== =========== =========== Crude oil posted reference price ($ per Bbl) (a) ............. $ 12.05 $ 25.60 $ 26.80 Estimated December 31 Company average realized price $/Bbl ..................................................... $ 9.36 $ 21.78 $ 23.72 $/Mcf (b) ................................................. $ 2.10 $ 2.25 $ 11.18
(a) 1998 price was based on year end West Texas Intermediate posted prices and 1999 and 2000 were based on year end NYMEX prices. (b) 1998 and 1999 prices were based on year end posted prices under our gas contracts. 2000 price was based on the year end NYMEX price of $9.78 per MMBTU. 63 64 COHO ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The following are the significant sources of changes in discounted future net cash flows relating to proved reserves:
1998 1999 2000 --------- --------- --------- Crude oil and natural gas sales, net of production costs ..... $ (41,412) $ (36,168) $ (60,862) Net changes in anticipated prices and production costs ....... (184,445) 582,297 65,129 Extensions and discoveries, less related costs ............... 39,510 7,683 24,387 Changes in estimated future development costs ................ (905) (19,335) 1,048 Development costs incurred during the period ................. 22,040 2,212 11,703 Net change due to sales and purchase of reserves in place .... (53,534) -- 1,616 Accretion of discount ........................................ 52,628 26,930 79,015 Revision of previous quantity estimates ...................... (20,178) 45,605 (90,700) Net changes in income taxes .................................. 58,084 (97,279) (63,033) Changes in timing of production and other .................... (70,683) (88,368) (64,889) --------- --------- --------- Net increase (decrease) ...................................... (198,895) 423,577 (96,586) Beginning of year ............................................ 468,193 269,298 692,875 --------- --------- --------- Standardized measure of discounted future net cash flows ..... $ 269,298 $ 692,875 $ 596,289 ========= ========= =========
15. SUBSEQUENT EVENTS Tunisian Operations. The Company decided to discontinue its participation in the exploration of two Tunisia, North Africa permits due to capital commitments during 2001 exceeding $7 million net to our interest, including cash calls currently due totaling $753,000 for January and February on the Anaguid permit. The Company owns a 45.8% interest in the Anaguid permit operated by Anadarko Tunisia Anaguid Company and a 12.5% interest in the Fejaj permit operated by Bligh Tunisia, Inc. The Company has been actively marketing its interests in these two permits since emerging from bankruptcy in March 2000 but has not been successful in selling such interests. The Company believes it is in its best interest to preserve its ownership in these permits under the protection of the bankruptcy court while it tries to negotiate sales of its interests in the permits to a third party or parties and to reach settlements with respect to its obligations under the permits. Therefore, the two subsidiaries that own these permits, Coho Anaguid, Inc. and Coho International Limited, filed for protection under Chapter 11 of the United States Bankruptcy Code on February 20, 2001. As a result, the Company took a writedown of $3.0 million during the fourth quarter of 2000. The Company anticipates that the other interest owners in these Tunisian permits will claim that these two subsidiaries are obligated for their share of the 2001 capital commitments totaling in excess of $7 million under the terms of the related operating and permit agreements. The Company is unable to determine the amount it may ultimately have to pay related to the 2001 capital commitments or the amount it may receive if it is successful in selling its Tunisian interests. Accordingly, no accrual for the resolution of these uncertainties has been made at December 31, 2000. The Chapter 11 filing included Coho Anaguid, Inc. and Coho International Limited. The following information summarizes the combined results of operations for these subsidiaries. This information has been prepared on the same basis as the consolidated financial statements.
Year Ended December 31, 2000 ----------------- Current assets ............................................ $ 9 -------- Total assets ............................................ $ 9 ======== Current liabilities ....................................... $ 625 Accounts payable to affiliates ............................ 9,601 Shareholder's equity ...................................... (10,217) -------- $ 9 ======== Operating expenses ........................................ $ 4,283 Net loss .................................................. $ 4,283
64 65 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 65 66 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item appears in the Company's proxy statement for the Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A, which information is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required by this item appears under the caption "Executive Compensation" set forth in the Company's proxy statement for the Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A, which information is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item appears under the caption "Security Ownership of Certain Beneficial Owners and Management" set forth in the Company's proxy statement for the Annual Meeting of Shareholders to be filed with the Securities Commission pursuant to Regulation 14A, which information is incorporated herein by references. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item appears under the caption "Certain Relationships and Related Transactions" set forth in the Company's proxy statement for the Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A, which information is incorporated herein by reference. 66 67 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) Documents Filed as a Part of this Report 1. FINANCIAL STATEMENTS Reference is made to the Index to Financial Statements under Item 8 on page 41. 2. FINANCIAL STATEMENT SCHEDULES All schedules and financial statements are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto listed above in Item 14(a) 1. 3. EXHIBITS
EXHIBIT NUMBER DESCRIPTION ------ ----------- 2.1 - Company's First Amended and Restated Chapter 11 Plan of Reorganization as filed with the United States Bankruptcy Court for the Northern District of Texas on February 14, 2000 (incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 2.2 - First Amended and Restated Disclosure Statement with respect to the Joint Plan of Reorganization under Chapter 11 of the United States Bankruptcy Code as filed with the United States Bankruptcy Court for the Northern District of Texas on February 14, 2000 (incorporated by reference to Exhibit 2.2 to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 2.3 - Findings of Fact, Conclusions of Law, and Order Confirming Debtors' First Amended and Restated Chapter 11 Plan of Reorganization as filed with the United States Bankruptcy Court for the Northern District of Texas on March 20, 2000 (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331). 3.1 - Form of Amended and Restated Articles of Incorporation of the Company (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 3.2 - Form of Amended and Restated Bylaws of the Company (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 4.1 - Form of Amended and Restated Articles of Incorporation (included as Exhibit 3.1 above). 4.2 - Form of Amended and Restated Bylaws of the Company (included as Exhibit 3.2 above). 10.1 - Credit Agreement dated as of March 31, 2000, among Coho Energy, Inc., The Chase Manhattan Bank, Meespierson Capital Corp., Fleet National Bank, Credit Lyonnais, New York Branch, ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.2 - First Amendment to Credit Agreement dated November 27, 2000 among Coho Energy, Inc., The Chase Manhattan Bank, Meespierson Capital Corp., Fleet National Bank, Credit Lyonnais, New
67 68 York Branch, ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE. 10.3 - Registration Rights Agreement dated as of March 31, 2000, among Coho Energy, Inc., PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Management L.P., as agent and on behalf of certain funds including Appaloosa Investment Limited Partnership I, Palomino Fund Ltd., and Tersk LLC; Pacholder Associates, Inc., as agent and on behalf of certain funds including Pacholder Value Opportunity Fund, L.P., High Yield Fund, Inc., One Group High Yield Bond and Evangelical Lutheran Church in America Board of Pensions; and Oaktree Capital Management, LLC, as general partner of an investment manager for the entities set forth therein (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.4 - Note Agreement dated as of March 31, 2000 among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana Production Company, Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Investment Limited Partnership I, Palomino Fund Ltd., Tersk LLC, Oaktree Capital Management, LLC, Pacholder Value Opportunity Fund, L.P., Pacholder High Yield Fund, Inc., One Group High Yield Bond Fund, and Evangelical Lutheran Church in America Board of Pensions (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.5 - Securities Purchase Agreement dated as of March 31, 2000, among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana Production Company, Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Management, L.P., Oaktree Capital Management, LLC, and Pacholder Associates, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.6 - Employment Agreement dated as of April 1, 2000 by and among Michael Y. McGovern and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.7 - Employment Agreement dated as of April 1, 2000 by and among Gary L. Pittman and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.8 - Employment Agreement dated as of April 1, 2000 by and among Gerald E. Ruley and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.9 - Form of Stay Agreement entered into with each of John L. Chadwick, Charles E. Gibson and Susan J. McAden.
68 69 10.10 - Letter agreement dated May 17, 2000 by and between Pirinate Consulting Group, LLC and Coho Energy, Inc. 10.11 - Crude Oil Purchase Contract dated January 25, 1996, by and between Coho Marketing and Transportation, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.12 - Adoption Agreement for Coho Resources, Inc.'s Amended and Restated 401(k) Savings Plan dated July 1, 1995 (incorporated by reference to Exhibit 10.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10.13 - Letter Agreement dated March 5, 1999, by and between Coho Marketing and Transportation, Inc. and Eott Energy Operating Limited Partnership, amending the Crude Oil and Purchase Contract dated January 25, 1996, by and between Coho Marketing and Transportation, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to Exhibit 10.27 to the Company's Registration Statement on Form S-1 (Registration Statement No. 333-96331)). 10.14 - Crude Oil Purchase Agreement dated October 1, 2000, by and between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M). 10.15 - Crude Oil Purchase Agreement dated September 20, 2000, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P. 10.16 - Crude Oil Purchase Contract dated December 19, 2000, by and between Coho Resources, Inc. and EOTT Energy Operating Limited Partnership. 21.1 - List of Subsidiaries of the Company (filed herewith).
* Represents management contract or compensatory plan or arrangement. The Company will furnish a copy of any exhibit described above to any beneficial holder of its securities upon receipt of a written request therefor, provided that such request sets forth a good faith representation that as of the record date for the Company's 2001 Annual Meeting of Shareholders, such beneficial holder is entitled to vote at such meeting, and upon payment to the Company of a fee compensating the Company for its reasonable expenses in furnishing such exhibits. (b) Reports on Form 8-K None. 69 70 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Coho Energy, Inc. Date: March 30, 2001 By: /s/ MICHAEL MCGOVERN ------------------------------------- Michael McGovern President and Chief Executive Officer Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- /s/ MICHAEL MCGOVERN President, Chief Executive March 30, 2001 - -------------------- Officer and Director Michael McGovern /s/ GARY L. PITTMAN Vice President and Chief March 30, 2001 - -------------------- Financial Officer Gary L. Pittman /s/ SUSAN J. MCADEN Controller and Chief March 30, 2001 - -------------------- Accounting Officer Susan J. McAden /s/ EUGENE L. DAVIS Director March 30, 2001 - -------------------- Eugene L. Davis /s/ JOHN G. GRAHAM Director March 30, 2001 - -------------------- John G. Graham /s/ JAMES E. BOLIN Director March 30, 2001 - -------------------- James E. Bolin /s/ RONALD GOLDSTEIN Director March 30, 2001 - -------------------- Ronald Goldstein /s/ MICHAEL SALVATI Director March 30, 2001 - -------------------- Michael Salvati
70 71 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION - ------- ----------- 2.1 - Company's First Amended and Restated Chapter 11 Plan of Reorganization as filed with the United States Bankruptcy Court for the Northern District of Texas on February 14, 2000 (incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 2.2 - First Amended and Restated Disclosure Statement with respect to the Joint Plan of Reorganization under Chapter 11 of the United States Bankruptcy Code as filed with the United States Bankruptcy Court for the Northern District of Texas on February 14, 2000 (incorporated by reference to Exhibit 2.2 to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 2.3 - Findings of Fact, Conclusions of Law, and Order Confirming Debtors' First Amended and Restated Chapter 11 Plan of Reorganization as filed with the United States Bankruptcy Court for the Northern District of Texas on March 20, 2000 (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331). 3.1 - Form of Amended and Restated Articles of Incorporation of the Company (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 3.2 - Form of Amended and Restated Bylaws of the Company (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 4.1 - Form of Amended and Restated Articles of Incorporation (included as Exhibit 3.1 above). 4.2 - Form of Amended and Restated Bylaws of the Company (included as Exhibit 3.2 above). 10.1 - Credit Agreement dated as of March 31, 2000, among Coho Energy, Inc., The Chase Manhattan Bank, Meespierson Capital Corp., Fleet National Bank, Credit Lyonnais, New York Branch, ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.2 - First Amendment to Credit Agreement dated November 27, 2000 among Coho Energy, Inc., The Chase Manhattan Bank, Meespierson Capital Corp., Fleet National Bank, Credit Lyonnais, New York Branch, ABN AMRO Bank N.V., General Electric Capital Corporation, CIBC Inc., Credit Agricole Indosuez, and Natexis Banque BFCE.
72 10.3 - Registration Rights Agreement dated as of March 31, 2000, among Coho Energy, Inc., PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Management L.P., as agent and on behalf of certain funds including Appaloosa Investment Limited Partnership I, Palomino Fund Ltd., and Tersk LLC; Pacholder Associates, Inc., as agent and on behalf of certain funds including Pacholder Value Opportunity Fund, L.P., High Yield Fund, Inc., One Group High Yield Bond and Evangelical Lutheran Church in America Board of Pensions; and Oaktree Capital Management, LLC, as general partner of an investment manager for the entities set forth therein (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.4 - Note Agreement dated as of March 31, 2000 among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana Production Company, Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Investment Limited Partnership I, Palomino Fund Ltd., Tersk LLC, Oaktree Capital Management, LLC, Pacholder Value Opportunity Fund, L.P., Pacholder High Yield Fund, Inc., One Group High Yield Bond Fund, and Evangelical Lutheran Church in America Board of Pensions (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). 10.5 - Securities Purchase Agreement dated as of March 31, 2000, among Coho Energy, Inc., Coho Resources, Inc., Coho Louisiana Production Company, Coho Exploration, Inc., Coho Oil & Gas, Inc., Interstate Natural Gas Company, PPM America Special Investments Fund, L.P., PPM America Special Investments CBO II, L.P., Appaloosa Management, L.P., Oaktree Capital Management, LLC, and Pacholder Associates, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.6 - Employment Agreement dated as of April 1, 2000 by and among Michael Y. McGovern and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.7 - Employment Agreement dated as of April 1, 2000 by and among Gary L. Pittman and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.8 - Employment Agreement dated as of April 1, 2000 by and among Gerald E. Ruley and Coho Energy, Inc. (incorporated by reference to the Company's Registration Statement on Form S-1 (Registration Number 333-96331)). *10.9 - Form of Stay Agreement entered into with each of John L. Chadwick, Charles E. Gibson and Susan J. McAden.
73 10.10 - Letter agreement dated May 17, 2000 by and between Pirinate Consulting Group, LLC and Coho Energy, Inc. 10.11 - Crude Oil Purchase Contract dated January 25, 1996, by and between Coho Marketing and Transportation, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.12 - Adoption Agreement for Coho Resources, Inc.'s Amended and Restated 401(k) Savings Plan dated July 1, 1995 (incorporated by reference to Exhibit 10.27 to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10.13 - Letter Agreement dated March 5, 1999, by and between Coho Marketing and Transportation, Inc. and Eott Energy Operating Limited Partnership, amending the Crude Oil and Purchase Contract dated January 25, 1996, by and between Coho Marketing and Transportation, Inc. and EOTT Energy Operating Limited Partnership (incorporated by reference to Exhibit 10.27 to the Company's Registration Statement on Form S-1 (Registration Statement No. 333-96331)). 10.14 - Crude Oil Purchase Agreement dated October 1, 2000, by and between Coho Oil & Gas, Inc. and Sunoco, Inc. (R&M). 10.15 - Crude Oil Purchase Agreement dated September 20, 2000, by and between Coho Oil & Gas, Inc. and TEPPCO Crude Oil, L.P. 10.16 - Crude Oil Purchase Contract dated December 19, 2000, by and between Coho Resources, Inc. and EOTT Energy Operating Limited Partnership. 21.1 - List of Subsidiaries of the Company (filed herewith).
* Represents management contract or compensatory plan or arrangement. The Company will furnish a copy of any exhibit described above to any beneficial holder of its securities upon receipt of a written request therefor, provided that such request sets forth a good faith representation that as of the record date for the Company's 2001 Annual Meeting of Shareholders, such beneficial holder is entitled to vote at such meeting, and upon payment to the Company of a fee compensating the Company for its reasonable expenses in furnishing such exhibits. EX-10.2 2 d85560ex10-2.txt 1ST AMENDMENT TO CREDIT AGREEMENT DATED 11/27/00 1 EXHIBIT 10.2 ================================================================================ FIRST AMENDMENT TO CREDIT AGREEMENT dated as of NOVEMBER 27, 2000 among COHO ENERGY, INC., as Borrower, THE CHASE MANHATTAN BANK, as Administrative Agent THE CHASE MANHATTAN BANK, as Issuing Bank MEESPIERSON CAPITAL CORP., as Documentation Agent FLEET NATIONAL BANK, as Syndication Agent and THE LENDERS PARTY HERETO ================================================================================ 2 FIRST AMENDMENT TO CREDIT AGREEMENT THIS FIRST AMENDMENT TO CREDIT AGREEMENT (this "Amendment"), is made as of November 27, 2000, among COHO ENERGY, INC., a Texas corporation (the "Borrower"), the various financial institutions as are, or may from time to time become, parties to the Credit Agreement (the "Lenders"), THE CHASE MANHATTAN BANK, as administrative agent for the Lenders (the "Administrative Agent"), THE CHASE MANHATTAN BANK, as Issuing Bank, MEESPIERSON CAPITAL CORP., as Documentation Agent, and FLEET NATIONAL BANK, as Syndication Agent. WITNESSETH: WHEREAS, the Borrower, the Lenders, the Agents and the Issuing Bank have heretofore entered into that certain Credit Agreement, dated as of March 31, 2000 (together with all amendments, supplements, restatements and other modifications, if any, from time to time thereafter made thereto, the "Credit Agreement"), and WHEREAS, the Borrower, the Lenders, the Agents and the Issuing Bank now intend to amend the Credit Agreement as set forth herein; NOW, THEREFORE, in consideration of the premises and the mutual agreements herein contained, each of the Borrower, the Lenders, the Agents, and the Issuing Bank hereby agree as follows: SECTION 1. Defined Terms. All capitalized terms used but not otherwise defined herein shall have the meanings given in the Credit Agreement, as amended by this Amendment. SECTION 2. Amendments to Credit Agreement. a. Section 5.16 of the Credit Agreement hereby is amended in its entirety to the following: " SECTION 5.16 Title Matters. (i) Prior to December 31, 2000, favorable title opinions and/or title reports as to the status of title to and Liens affecting the Amoco Properties containing at least thirty-seven and one-half percent (37.5%) of the Proven Reserves as of the Effective Date attributable to the Amoco Properties, and (ii) prior to February 15, 2001, favorable title opinions and/or title reports as to the status of title to and Liens affecting the Amoco Properties containing at least an additional thirty-seven and one-half percent (37.5%) of the Proven Reserves as of the Effective Date attributable to the Amoco Properties, each such title opinion and/or title report to be addressed to the Administrative Agent and the Lenders and issued by counsel to the Borrower, satisfactory to the Administrative Agent in its reasonable discretion. Such opinions and/or title reports may contain (i) in the case of any Amoco Properties comprised of oil and gas leases or interests therein, or participating 3 mineral interests substantially all of which were acquired by Amoco Production Company or any of its Affiliates or Mobil Oil Corporation, Mobil Rocky Mountain, Inc. or any of their Affiliates or any corporate predecessors of any of them and held by such entities for more than twenty-five (25) years prior to the acquisition thereof by Coho Acquisitions Company, assumptions regarding the status of title to the lands covered by such oil and gas leases or interests therein at the time of such lease or mineral acquisition by such predecessors in title, and (ii) subject to the consent of the Administrative Agent, such other reasonable assumptions, exceptions and qualifications as are customary for opinions or reports of that type." b. Section 5.17 of the Credit Agreement hereby is amended in its entirety to the following: " SECTION 5.17 Florabama Settlement. Within ten (10) Business Days of any of the Borrower, Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production Company or Interstate Natural Gas Company entering into an agreement or other settlement resolving, in whole or in part, the claims of Florabama Associates, Ltd. against the Borrower or such Subsidiaries of the Borrower in connection with the Bankruptcy Case (the "Settlement"), the Borrower will deliver to the Administrative Agent a copy of the Settlement Agreement certified as of the date thereof by the Secretary or Assistant Secretary of the Borrower (i) to be a true, correct and complete copy of such Settlement Agreement and (ii) not to have been amended or rescinded from the form so certified. Within ten (l0) Business Days of the Bankruptcy Court approving such Settlement Agreement, the Borrower will deliver to the Administrative Agent a copy of any order of the Bankruptcy Court and any other documentation associated with the Settlement Agreement certified as of the date thereof by the Secretary or Assistant Secretary of the Borrower (i) to be true, correct and complete copies of such documents and (ii) not to have been amended or rescinded from the form so certified and to be in full force and effect." c. Article VI of the Credit Agreement hereby is amended by inserting the following Section 6.17 after Section 6.16 thereof: " SECTION 6.17 Florabama Settlement. The Borrower will not, and will not permit Coho Resources, Inc., Coho Oil & Gas, Inc., Coho Exploration, Inc., Coho Louisiana Production Company or Interstate Natural Gas Company to, enter into a Settlement Agreement either (i) in violation of the terms and conditions of the Confirmation Order or (ii) in an aggregate amount for all amounts to be paid by the Borrower and any of its Subsidiaries in connection with the Settlement Agreement in excess of $1,047,000." SECTION 3. Representations and Warranties. To confirm each Lender's understanding concerning Borrower and its businesses, properties and obligations, and to induce the Agents, the 2 4 Issuing Bank and each Lender to enter into this Amendment, the Borrower hereby reaffirms to the Agents, the Issuing Bank and each Lender that, as of the date hereof, its representations and warranties contained in Article III of the Credit Agreement and in the other Loan Documents to which it is a party (except to the extent such representations and warranties relate solely to an earlier date) are true and correct and additionally represents and warrants as follows: a. The execution, delivery and performance by the Borrower of this Amendment and each other Loan Document executed or to be executed by it, and the execution, delivery and performance by each other Obligor of each Loan Document executed or to be executed by it, are within the Borrower's and each such Obligor's corporate, limited liability company and/or partnership powers, and have been duly authorized by all necessary corporate, limited liability company and/or partnership action, and if required, stockholder, member and/or partner action. This Amendment has been duly executed and delivered by the Borrower and this Amendment and the Credit Agreement as amended by this Amendment each constitute, and each other Loan Document executed or to be executed by any Obligor, when executed and delivered by such Obligor, will constitute, a legal, valid and binding obligation of the Borrower or such Obligor (as the case may be), enforceable in accordance with their respective terms. b. The execution, delivery and performance by the Borrower of this Amendment, the Credit Agreement and each other Loan Document executed or to be executed by it, and the execution, delivery and performance by each other Obligor of each Loan Document executed or to be executed by it, (a) do not require any Governmental Approval or third party approvals, except such as have been obtained or made and are in full force and effect and except filings necessary to perfect Liens created under the Loan Documents, (b) will not violate any applicable Governmental Rule or the Organic Documents of the Borrower or any such Obligor or any order of any Governmental Authority, (c) will not violate or result in a default under any indenture, agreement or other instrument binding upon the Borrower or any such Obligor or its assets, or give rise to a right thereunder to require any payment to be made by the Borrower or any such Obligor, and (d) will not result in the creation or imposition of any Lien on any asset of the Borrower or any such Obligor except Liens created under the Loan Documents. SECTION 4. Effectiveness. This Amendment shall become effective as of the date hereof when counterparts hereof executed on behalf of the Borrower and the Required Lenders (or notice thereof satisfactory to the Administrative Agent) shall have been received by the Administrative Agent. SECTION 5. Reaffirmation of Credit Agreement. This Amendment constitutes a "Loan Document" as defined in the Credit Agreement and shall be deemed to be an amendment of the Credit Agreement, and the Credit Agreement, as amended and restated hereby, is hereby ratified, approved and confirmed in each and every respect. All references to the Credit Agreement in any other document, instrument, agreement or writing shall hereafter be deemed to refer to the Credit Agreement as amended by this Amendment. 3 5 SECTION 6. Counterparts. This Amendment may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall constitute one and the same Amendment. SECTION 7. GOVERNING LAW. THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE INTERNAL LAW OF THE STATE OF TEXAS WITHOUT GIVING EFFECT TO CHOICE OF LAW PRINCIPLES. SECTION 8. Severability. Any provision of this Amendment held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof; and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction. SECTION 9. Entire Agreement. THIS WRITTEN AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. [SIGNATURES BEGIN ON FOLLOWING PAGE] 4 6 IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written. COHO ENERGY, INC. By: /s/ GARY L. PITTMAN -------------------------- Name: Gary L. Pittman Title: Chief Financial Officer S-1 7 THE CHASE MANHATTAN BANK, individually as a Lender and as Administrative Agent By: /s/ RUSSELL A. JOHNSON --------------------------- Name: RUSSELL A. JOHNSON Title: VICE PRESIDENT S-2 8 THE CHASE MANHATTAN BANK, as Issuing Bank By: /s/ RUSSELL A. JOHNSON ---------------------- Name: RUSSELL A. JOHNSON Title: VICE PRESIDENT S-3 9 FORTIS CAPITAL CORP (formerly MEESPIERSON CAPITAL CORP.) individually as a Lender and as Documentation Agent By: /s/ CHRISTOPHER S. PARADA --------------------------- Name: CHRISTOPHER S. PARADA Title: VICE PRESIDENT By: /s/ DARRELL W. HOLLEY --------------------------- Name: DARRELL W. HOLLEY Title: MANAGING DIRECTOR S-4 10 FLEET NATIONAL BANK, individually as a Lender and as Syndication Agent By: /s/ TERRENCE RONAN ---------------------------------- Name: TERRENCE RONAN Title: DIRECTOR S-5 11 CREDIT LYONNAIS, NEW YORK BRANCH, individually as Lender By: /s/ PHILIPPE SOUSTRA ---------------------------------- Name: Philippe Soustra Title: Senior Vice President By: ---------------------------------- Name: Title: S-6 12 ABN AMRO BANK N.V., individually as Lender By: /s/ RODNEY D. KUBICEK ---------------------------------- Name: Rodney D. Kubicek Title: Vice President By: /s/ JAMIE A. CONN ---------------------------------- Name: Jamie A. Conn Title: Vice President S-7 13 GENERAL ELECTRIC CAPITAL CORPORATION, individually as Lender By: /s/ PAUL A. JORDAN ---------------------------------- Name: Paul A. Jordan Title: Portfolio Manager S-8 14 CIBC INC., individually as Lender By: /s/ M. BETH MILLER ---------------------------------- Name: M. BETH MILLER Title: AUTHORIZED SIGNATORY By: ---------------------------------- Name: Title: S-9 15 CREDIT AGRICOLE INDOSUEZ, individually as Lender By: /s/ BRIAN KNEZEAK ---------------------------------- Name: Brian Knezeak Title: FVP, Manger By: /s/ MICHAEL D. WILLIS ---------------------------------- Name: Michael D. Willis Title: Vice President, Credit Analysis S-10 16 NATEXIS BANQUES POPULAIRES, individually as Lender By: /s/ DONOVAN C. BROUSSARD ---------------------------------- Name: Donovan C. Broussard Title: Vice President By: /s/ RENAUD J. D'HERBES ---------------------------------- Name: Renaud J. d'Herbes Title: Senior Vice President and Regional Manager S-11 EX-10.9 3 d85560ex10-9.txt FORM OF STAY AGREEMENT 1 EXHIBIT 10.9 STAY AGREEMENT This Stay Agreement (the "Agreement") dated as of November __, 2000 between Coho Energy, Inc., a Texas corporation (the "Company") and _____________________ (the "Key Employee"). WITNESSETH WHEREAS the Company has adopted a plan (the "Stay Plan") designed to ensure the retention of key personnel and to motivate them to manage the Company's business effectively; WHEREAS the Company has designated the Key Employee as a participant in the Stay Plan; provided that such designation may be revoked under certain circumstances as provided herein; NOW THEREFORE, the parties hereto hereby agree to follows: 1. Stay Bonus, (a) Subject to all of the terms and conditions of this Agreement, the Company shall pay, or cause to be paid, to the Key Employee a lump sum in the amount of one year salary (the "Stay Bonus"), if the Key Employee continues to be employed by the Company or its Subsidiaries for a period (the "Stay Period") of not less than 180 days after consummation of a Change of Control, or, if there is a Specified Termination Event, as hereinafter defined, prior to the expiration of the Stay Period. The Stay Bonus shall be payable on the earlier of 10 days after the expiration of the Stay Period or if there is a Specified Termination Event prior to the expiration of the Stay Period, 10 days after the later of the Specified Termination Event or the Consummation Date. (b) All payments hereunder, to the extent required by law, will be made by the Company net of withholding, social security, Medicare and other similar taxes and levies. (c) In the event that the Key Employee is entitled to receive any payment pursuant to this Agreement and the Key Employee dies after such payment is due hereunder but before such payment is made, such payment shall be made to the Key Employee's beneficiary designated hereunder; provided that nothing contained in this paragraph is intended to increase any compensation or benefits provided to the Key Employee under this Agreement. At any time after the execution of this Agreement, the Key Employee may prepare, execute, and file with the Secretary of the Company a designation of beneficiary. The Key Employee shall thereafter be free to change beneficiary by filing a new designation of beneficiary with the Secretary of the Company. In the event the Key Employee fails to designate a beneficiary, following the death of the Key Employee all payments of the amounts specified by this Agreement which would have been paid to the Key Employee's designated beneficiary pursuant to this Agreement shall instead be paid to the Key Employee's spouse, if any, if she survives the Key 2 Employee or, if there is no spouse or she does not survive the Key Employee, to the Key Employee's estate. (d) This Agreement shall not constitute a guarantee of continuing employment. (e) Any termination of the Key Employee's employment by the Company or by the Key Employee (other than termination by reason of death) shall be communicated by written notice to the other party, which notice shall indicate the reason for such termination and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis therefor. (f) As used herein, the following terms shall have the following respective meanings: "CAUSE" shall mean (i) the engaging by the Key Employee in willful misconduct that is injurious to the Company or its Subsidiaries (ii) the embezzlement or misappropriation of funds or property of the Company or its Subsidiaries by the Key Employee or the conviction of the Key Employee of a felony or the entrance of a plea of guilty or nolo contendere by the Key Employee to a felony, or (iii) the willful failure or refusal by the Key Employee to substantially perform his duties or responsibilities that continues after being brought to the attention of the Key Employee (other than any such failure resulting from the Key Employee's incapacity due to Disability). For purposes of this paragraph, no act, or failure to act, on the Key Employee's part shall be considered "willful" unless done, or omitted to be done, by him not in good faith and without reasonable belief that his action or omission was in the best interest of the Company. Determination of Cause shall be made by the Compensation Committee in their sole discretion. Any such determination shall be final and binding on the Key Employee. "CHANGE OF CONTROL" means (a) the sale, lease or other transfer of all or substantially all of the assets of the Company to any person or group (as such term is used in Section 13 (d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")); (b) the adoption by the stockholders of the Company of a plan relating to the liquidation or dissolution of the Company; (c) the merger or consolidation of the Company with or into another entity or the merger of another entity into the Company or any subsidiary thereof with the effect that immediately after such transaction the stockholders of the Company immediately prior to such transaction (or their affiliates) hold less than fifty percent (50%) of the total voting power of all securities generally entitled to vote in the election of directors, managers or trustees of the entity surviving such merger or consolidation; or (d) the acquisition by any person, entity or 3 group, within the meaning of Section 13(d) or 14(d) of the Exchange Act (other than PPM America, Inc., Appaloosa Management LP, Oaktree Capital Management LLC, their respective affiliates or managed funds, or any group consisting of any of them), of more than fifty percent (50%) of the voting power of all securities of the Company generally entitled to vote in the election of directors of the Company. "CONSUMMATION DATE" shall mean the date on which a Change of Control becomes effective. "DISABILITY" shall mean the good faith determination of the Compensation Committee that the Key Employee has become physically or mentally disabled or incapacitated to the extent that he is unable to perform his duties hereunder, and that such disability or incapacity has continued for a period of ninety (90) consecutive days; provided, that in reaching its determination, the Compensation Committee shall consider medical evaluations by a physician selected by the Key Employee and a physician selected by the Company (if the Key Employee fails or refuses to submit to a medical examination, within thirty (30) days after the Company so requests, by a physician selected by the Company, then the conditions set forth in this definition shall be deemed to have been satisfied upon the expiration of such thirty (30) day period). "GOOD REASON" shall mean, so long as the Key Employee has not been guilty of the conduct described in clause (i), (ii) or (iii) of the definition of "Cause" herein, (i) a reduction in the Key Employee's base salary in effect immediately prior to the Effective Date, (ii) a material change in the terms of any incentive compensation or bonus plan in which the Key Employee participated immediately prior to the Effective Date if the effect thereof is to reduce the potential compensation to the Key Employee thereunder, unless in the case of clauses (i) or (ii) above, the Key Employee agrees in writing such reduction of base salary or change in incentive compensation or bonus plan, or (iii) the relocation by the Company of the Key Employee's office to a location outside a 20 mile radius of Dallas, Texas. "SPECIFIED TERMINATION EVENT" shall mean the termination of the Key Employee's employment (i) by the Company other than by reason of the Key Employee's death or Disability or for Cause, or (ii) by the Key Employee for Good Reason. 2. Term. (a) Effective Date. This Agreement shall become effective on the date (the "Effective Date") of execution of this Agreement by the Company and the Key Employee. 4 (b) Termination Date. The term of this Stay Agreement is until December 31, 2002 (the "Termination Date"). 3. Representations. (a) The Company represents and warrants that this Agreement has been authorized by all necessary corporate action of the Company. (b) The Key Employee represents and warrants that he is not a party to any agreement or instrument that would prevent him from entering into or performing his duties in any way under this Agreement. 4. Compensation Committee. The Compensation Committee of the Board of Directors of Coho Energy, Inc. ("Compensation Committee") shall be responsible for the administration and interpretation of this Agreement. Any provisions of this Agreement to the contrary notwithstanding, the Compensation Committee (i) may shorten the Stay Period with respect to the Key Employee or (ii) may revoke the Key Employee's designation as a participant in the Stay Bonus, without payment or penalty, at any time prior to the end of the Stay Period if, the Compensation Committee determine, in their sole discretion, that, the Key Employee has failed to continue to perform his duties in a diligent and proper manner throughout the Stay Period, or has taken any action which is inconsistent with his duty of loyalty and duty of care to the Company. Before reaching its determination under clause (ii) of the preceding sentence, the Compensation Committee shall give the Key Employee five (5) days prior notice and, if requested by the Key Employee, the opportunity to appear before the Compensation Committee within five (5) days after such notice is given. Any action to be taken by the Compensation Committee shall be taken by majority vote or action. The initial Compensation Committee shall be Ron Goldstein, Michael Salvati and Michael McGovern. Upon death or resignation of any member of the Compensation Committee, the remaining Compensation Committee then in office shall have the power to fill such vacancy. 5. Entire Agreement. This Agreement contains all the understandings between the parties hereto pertaining to the matters referred to herein, and supersedes all undertakings and agreements, whether oral or in writing, previously entered into by them with respect thereto. The Key Employee represents that, in executing this Agreement, he does not rely and has not relied upon any representation or statement not set forth therein made by the Company with regard to the subject matter, bases or effect of this Agreement or otherwise. 6. Amendment or Modification, Waiver. No provision of this Agreement may be amended or waived unless such amendment or waiver is agreed to in writing, signed by the Key Employee and by a duly authorized representative of the Compensation Committee. No waiver by any party hereto of any breach by another party hereto of any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of a similar or dissimilar condition or provision at the same time, any prior time or any subsequent time. 5 7. Notices. Any notice to be given hereunder shall be in writing and shall be deemed given when delivered personally, sent by courier or telecopy or registered or certified mail, postage prepaid, return receipt requested, addressed to the party concerned at the address indicated below or to such other address as such party may subsequently give notice of hereunder in writing: To Key Employee at: ------------------- To the Company at: Coho Energy, Inc. 14785 Preston Road Suite 860 Dallas, Texas 75240 Attn: President Any notice delivered personally or by courier under this Section 6 shall be deemed given on the date delivered and any notice sent by telecopy or registered or certified mail, postage prepaid, return receipt requested, shall be deemed given on the date telecopied or mailed. 8. Arbitration/Awards. Any claim or dispute arising out of this Agreement shall be submitted to binding arbitration in Dallas, Texas, pursuant to the commercial arbitration rules of the American Arbitration Association ("AAA"), with each party selecting one arbitrator from a list of qualified arbitrators submitted by the AAA, and those two arbitrators selecting a single qualified arbitrator who will arbitrate the matter. The arbitrators selected will be attorneys with at least five years of business law experience. The decision of the selected arbitrators shall be final and binding on both the Key Employee and the Company, without appeal, and any such decision may be entered and enforced as a final judgement or order through any Federal or state court within or outside of the United States. The Company agrees that in any such proceeding the Key Employee shall be entitled to recover pre-judgment interest on any amount awarded, together with reasonable attorney's fees and expenses but in no event shall the Key Employee be entitled to recovery of punitive or exemplary damages. 9. Failure to Enforce and Waiver. The failure to insist upon strict compliance with any of the terms, convenants or conditions of this Agreement shall not be deemed by waiver of such terms, covenants or conditions, and the waiver or relinquishment of any right or power under this Agreement at any one or more times shall not be deemed a waiver or relinquishment or such right or power at any other time or times. 6 10. Severability. If any provision of this Agreement or the application of any such provision to any party or circumstances shall be determined by any court of competent jurisdiction to be invalid and unenforceable to any extent, the remainder of this Agreement or the application of such provision to such person or circumstances other than those to which it is so determined to be invalid and unenforceable, shall not be affected thereby, and each provision hereof shall be validated and shall be enforced to the fullest extent permitted by law. 11. Survival. The respective rights and obligations of the parties hereunder shall survive any termination of this Agreement to the extent necessary to the intended preservation of such rights and obligations. 12. Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, without regard to its conflicts of laws principles. 13. Headings. All descriptive headings of sections and paragraphs in this Agreement are intended solely for convenience, and no provision of this Agreement is to be construed by reference to the heading of any section or paragraph. ------------------------------------- COHO ENERGY, INC. By: ------------------------------------- Michael Y. McGovern President and Chief Executive Officer EX-10.10 4 d85560ex10-10.txt LETTER AGREEMENT DATED 5/17/00 1 EXHIBIT 10.10 [PIRINATE CONSULTING GROUP, LLC LETTERHEAD] May 17, 2000 Michael McGovern Chief Executive Officer Coho Energy, Inc. 14785 Preston Road Suite 860 Dallas, Texas 75240 Dear Michael: When executed in the space provided below, this letter agreement ("Agreement") shall serve to memorialize the terms and conditions of the retention of PIRINATE Consulting Group, LLC ("PIRINATE") by Coho Energy, Inc. ("Coho") with respect to consulting services to be rendered by PIRINATE to Coho, as follows: 1. The effective date of the Agreement shall be April 1, 2000. PIRINATE shall provide the personal services of Eugene Davis ("Davis") to Coho with respect to projects assigned by the Board of Directors of Coho ("Board"). 2. Projects assigned to Davis shall include assistance with respect to the operational and financial matters of Coho, resolution of the pending litigation with affiliates of Hicks, Muse and disposition of Coho's interest in its Tunisian concession. 3. PIRINATE will initially receive a retainer of $15,000 per each month or portion of a month that services are rendered hereunder. The retainer shall cover an average five (5) to six (6) business days' services per calendar month, whether rendered at Coho's Dallas offices or elsewhere, additional days shall be billed at $2500 per day. The retainer is payable in advance and is due by the first day of the month in which services are to be rendered. PIRINATE will provide a monthly invoice for such retainer, which shall be payable on receipt and which will include a statement of the prior month's out-of-pocket expenses to be reimbursed by Coho and charges for any additional days' services provided in such prior month. Any additional days' services beyond the services covered by the monthly retainer and any major expenses must be approved in advance by the Executive Committee of the Board. Any expenses shall be consistent with expense guidelines applicable to senior executives of Coho. 4. It is recognized that Davis is currently a member of the Board and that any compensation received by Davis with respect to his activities as a Director shall be in addition to and shall not prejudice or be prejudiced by any compensation received or services performed hereunder. 2 Page 2 May 17, 2000 5. PIRINATE and Davis shall maintain all non-public information of Coho as strictly confidential except to the extent otherwise required by applicable law or court order. 6. Either party may terminate this agreement, with or without cause, upon sixty (60) days prior written notice. Any termination shall be without prejudice to PIRINATE's right to receive retainer payments, payments for additional days' services and reimbursement of expenses for all periods prior to the effective date of such termination. PIRINATE greatly appreciates the opportunity of assisting you and your management team in creating a stronger and more profitable Coho. Please indicate your acceptance of the foregoing terms and conditions by executing a counterpart of this Agreement in the space provided below and returning same together with the retainer payment for the first month of the engagement to the address set forth above. Sincerely, /s/ EUGENE I. DAVIS Eugene I. Davis Chairman and Chief Executive Officer Agreed and accepted this 22nd day of May, 1999 by: Coho Energy, Inc. By: /s/ MICHAEL Y. MCGOVERN ---------------------------------------------- Michael Y. McGovern Chief Executive Officer EX-10.14 5 d85560ex10-14.txt CRUDE OIL PURCHASE AGREEMENT - SUNOCO, INC. 1 EXHIBIT 10.14 [SUNOCO, INC. LETTERHEAD] [SUNOCO, INC. LOGO] CRUDE OIL PURCHASE AGREEMENT SUNOCO REFERENCE NO. 502685 This agreement, made and entered into as of October 1, 2000, and between "Buyer" and "Seller" as follows:
Buyer: Seller: - ------ ------- Sunoco, Inc. (R&M) Coho Oil & Gas, Inc. ("SUNOCO") 14785 Preston Road, Ste. 860 P0 Box 2039 Dallas, TX 75240 Tulsa, OK 74102
WITNESSETH: WHEREAS, Seller owns or is authorized to sell all of the volumes of crude oil and condensate produced from the properties described in Exhibit "A" attached hereto; and WHEREAS, Buyer desires to purchase and receive said crude oil and condensate and Seller desires to sell and deliver said crude oil and condensate in accordance with the terms of this agreement; 1. Sale and Purchase. Subject to the provisions hereof, Seller shall sell to Buyer and Buyer shall purchase from Seller all of the crude oil and condensate produced from the properties described in Exhibit "A" attached hereto. Seller hereby commits and dedicates to the performance of this agreement all of the crude oil and condensate produced from the lease(s) included on Exhibit "A" attached hereto. The parties hereto, by mutual consent, may amend this agreement at any time to include additional properties to Exhibit "A". 2. Term. This agreement shall remain in effect for an initial term of one (1) year commencing on October 1, 2000, and from month to month thereafter, unless and until terminated by either party upon written notice thereof given thirty (30) days in advance of the end of the primary term of this agreement or any extension thereof. 3. Delivery Point. Delivery shall take place and title shall pass from the Seller to the Buyer when the crude oil passes the outlet flange of the Seller's lease facility to the receiving equipment of Buyer or Buyer's designated agent. 4. Warranty of Title and Authority to Sell. Seller hereby warrants and guarantees that the title to the portion of the crude oil sold and delivered hereunder which is owned by Seller is free and clear of all liens and encumbrances and warrants that as to the remaining portion of the crude oil sold and delivered hereunder Seller has the right and authority to sell and deliver said crude oil for the benefit of the true owners thereof. Seller further warrants that the crude oil has been produced, handled, and transported to the delivery point hereunder, in accordance with the laws, rules and regulations of all governmental authorities having jurisdiction thereof. Seller shall indemnify and hold Buyer harmless from and against any and all cost, damage and expense suffered and incurred by reason of any failure of the title so warranted or any inaccuracy in the representation of Seller's right and authority to sell said crude oil made herein. 5. Price. For those leases listed on the attached Exhibit "A" and any additions thereto, the U.S. dollar price per barrel for each delivery month shall be: The simple average of daily settling price of the near month NYMEX light sweet crude oil contract during the calendar month of delivery minus (-) fifty cents ($0.50) per barrel. 2 Coho Oil & Gas, Inc. - Copa#502685 October 31, 2000 Page 2 e.g. for Oct, 2000 deliveries, the average of NYMEX settling prices for November Light Sweet crude contract from Oct 1, 2000 through Oct 22, 2000, and December Light Sweet crude contracts from Oct 21, 2000, through Oct 31, 2000, shall apply. This simple average shall be calculated to allow the averaging of settling prices only, as determined by the NYMEX. Saturdays, Sundays, and holidays are not included in the calculation therefore only NYMEX trading days will be averaged in the above calculation. For pricing purposes, the oil delivered during any given calendar month hereunder shall be deemed to have been delivered in equal daily quantities for each day of the given month. Buyer and Seller agree that for the term of this agreement and any extensions thereof, Seller shall not incur gravity penalties. 6. Manner of Payment. Subject to verification of deliveries, payment for crude oil sold and delivered Shall be made by check on or about twenty-third (23rd) day of the month following the month of delivery. Payment shall be made to the Seller utilizing Buyer's Division Order excluding taxes. 7. Taxes. Buyer is hereby authorized to withhold from the proceeds allocable to the sale and delivery of crude oil hereunder the amount of severance taxes levied by Indian Tribes, State and Federal Agencies. 8. Prevailing Document. In the event of any conflict between the provisions of this agreement and the provisions of any applicable division order executed in accordance with the terms hereof, the provisions of this agreement shall control. 9. Quality Requirements. If the crude oil shall not meet Sunoco's Oklahoma Sweet requirements at the delivering point, then Buyer shall have the right to terminate this Crude Oil Purchase Agreement by giving thirty (30) days written notice. 10. General Provisions. The General Provisions attached to this agreement are made a part of this agreement. ALL SIGNATURES MUST BE WITNESSED COHO OIL & GAS, INC. SUNOCO, INC. (R&M) Witness By /s/ KAREN S. COOK -------------------------------- /s/ ELAINE SMITH Karen S. Cook - ------------------------------------ Title Sr. Crude Oil Representative ----------------------------- SELLER Witness: By /s/ GARY L. PITTMAN -------------------------------- /s/ IRENE REYES - ------------------------------------ Title CFO ----------------------------- 3 SUNOCO, INC. (R&M) COPA GENERAL PROVISIONS 1. Existing Laws. This Agreement will be governed by existing laws of the State of Oklahoma. 2. Force Majeure. Neither party shall be liable to the other for failure or delay in making or accepting deliveries hereunder to the extent that such failure or delay may be due to compliance with acts, orders, regulations or requests of any federal, state or local civilian or military authority or as a result of insurrections, wars, rebellion, riots, strikes, labor difficulties, action of the elements, disruption or breakdown of production or transportation facilities, or any other cause, whether or not of the same class or kind, reasonably beyond the control of such party. 3. Quality and Measurement. Seller warrants that all crude oil purchased hereunder shall be of merchantable quality (that is, unaltered and uncontaminated by any foreign substances or chemicals not normally associated with oil) and suitability shall be determined within the Buyer's exclusive, good faith opinion. Quantities of oil delivered hereunder shall be determined by a method of measurement generally accepted within the industry including, but not limited to, the use of automatic measuring equipment, tank gauges on l00% tank table basis, and certified truck gauges and meters. Meters shall be proven in accordance with the latest American Petroleum Institute standards. Volume shall be measured in barrels of forty-two (42) U.S. Gallons as adjusted for temperature to 60 degrees Fahrenheit, less deductions for basic sediment and water and other impurities determined according to applicable API practices. Oil containing basic sediment and water in excess of the quantity permitted by the carrier's tariff shall be treated by Seller to render it merchantable. Tests for quality shall be made at regular intervals by Buyer or Buyer's Agent in accordance with recognized procedures. Each party shall have the right to have a representative present to witness all tests and measurements but in the absence of either party's representative, the results of the tests and measurements performed by the Buyer shall be deemed to be conclusive. 4. Waiver. Failure by either party to object to any failure of performance by the other party of any provision of this Agreement shall not constitute a waiver of, or estoppel against, the right of such party to require such performance by the other. Nor shall any such failure to object constitute a waiver or estoppel with respect to any succeeding failure of performance. 5. Assignment. This Agreement shall not be assignable by either party without the prior written consent of the other. Any attempted assignment without such consent shall be void. 6. Compliance with Laws. Each party agrees that the performance of this contract shall comply with all applicable state, federal and local laws. Each party shall supply evidence of compliance, if required. 7. Security. If, in the reasonable opinion of either party, the financial responsibility of the other party is or becomes impaired or unsatisfactory, or if the other party fails to make any payment or delivery when required, the requesting party may require satisfactory security to secure performance or payment or both, whether by way of stand-by or documentary letter of credit, guaranty, advance payment, or otherwise. Failure to provide the required security shall constitute a material breach of the Agreement entitling the requesting party to cancel or suspend its delivery obligation and to offset any payments or deliveries due the other party under this Agreement or other Agreements between the two parties. 8. Damages. The parties agree that in the event of a material breach of the Agreement resulting from a repudiation of an obligation or a failure to deliver or receive all or a material portion of the required quantities, the non-breaching party shall be entitled to recover contract damages, administrative costs for any cover or resale and any other costs including but not limited to court costs and reasonable legal fees incurred in recovering such damages. EX-10.15 6 d85560ex10-15.txt CRUDE OIL PURCHASE CONTRACT - TEPPCO CRUDE OIL LP 1 EXHIBIT 10.15 [TEPPCO LETTERHEAD] Date of Contract September 20, 2000 TEPPCO Contract Number: COH-P00102117-M ---------------- TEPPCO Contact: Ted Parrish ---------------- Customer Contract Number: ---------------- COHO OIL & GAS, INC. Attn: Gary Pittman 14785 Preston Road, Suite 860 Dallas, TX 75240 Phone: (972) 774-8305 FAX: NA This agreement (the "Contract") is made between TEPPCO Crude Oil, L.P. ("TCO") and Coho Oil & Gas, Inc. ("Coho") whereby Coho agrees to sell and deliver and TCO agrees to purchase and receive crude oil and condensate under the terms and conditions set forth herein. COHOS SALE AND DELIVERY TO TCO 1. QUALITY: 1) Oklahoma Sour Crude Oil 2) Oklahoma Sweet Crude Oil 2. QUANTITY: 1) Equal to the production from leases listed on Exhibit A 2) Equal to the production from leases listed on Exhibit B 3. DELIVERY: 1) Into the designated carrier as shown on Exhibit A 2) Into the designated carrier as shown on Exhibit B 4. PRICE: 1) The simple monthly average of the daily settlement price of the Nymex crude oil contract, during the month of delivery (trading days only) deemed 40 degrees and deemed delivered in equal daily quantities minus Platt's West Texas Sour,/West Texas Intermediate differential, less the amount shown on Exhibit A. 2) The simple monthly average of the daily settlement price of the Nymex crude oil contract, during the month of delivery (trading days only) deemed 40 degrees and deemed delivered in equal daily quantities less the amount shown on Exhibit B. 5. TERM: Commencing October 1, 2000 through September 30, 2001, thereafter month to month until canceled by either party upon thirty (30) days advanced written notice 6. PAYMENT: Shall be made on the 20th of the month following delivery via net out and/or wire transfer at a bank of seller's choice. If payment due date falls on a Sunday or Monday banking holiday, payment will be made effected on the following business day. If payment due date falls on a Saturday or a banking holiday other than a Monday, then payment will be effected on the preceding day 7. GENERAL All other terms and conditions not specifically stated shall be TERMS AND governed by TEPPCO Crude Oil, LP's General Provisions attached CONDITIONS: hereto and made a part hereof 8. SPECIAL This contract is based on an estimated volume of approximately PROVISION: 3,000 barrels per day of production. If that volume increases by more than 10%, the excess above that percent will be priced based on the then current market price. This Contract contains the complete agreement of both parties and cannot be modified unless in writing. Photocopies and faxes of signed copies of the Contract shall have the same force and effect as signed originals. Please execute this Contract by return FAX (405) 232-1815 to TEPPCO Crude Oil, L.P., Attn: Contract Administrator within five (5) business days. TEPPCO CRUDE OIL, L.P. By TEPPCO Crude GP, LLC its general partner By: /s/ J. MICHAEL COCKRELL ------------------------- J. Michael Cockrell, President COHO OIL & GAS, INC. By: /s/ GARY L. PITTMAN ---------------------------- Title: CFO ---------------------------- Date: 12/22/00 ---------------------------- 2 ATTACHED TO AND MADE PART OF THAT CERTAIN CRUDE OIL PURCHASE CONTRACT DATED SEPTEMBER 20, 2000 BETWEEN TEPPCO CRUDE OIL, LP. AND COHO OIL & GAS, INC. GENERAL TERM AND CONDITIONS A. MEASUREMENT AND TESTS: All measurements hereunder shall be made from static tank gauges on 100 percent tank table basis or by positive displacement meters. All measurements and tests shall be made in accordance with the latest ASTM or ASMEAPI (Petroleum PD Meter Code) published methods then in effect, whichever apply. Volume and gravity shall be adjusted to 60 degrees Fahrenheit by the use of Table 6A and 5A of the Petroleum Measurement Tables ASTM Designation D1250 In their latest revision. The Product delivered hereunder shall be marketable and acceptable in the applicable common or segregated stream of the Carriers involved but not exceed 1% S&W. Full deduction for all free water and S&W content shall be made according to the API/ASTM Standard Method then in effect. Either Party shall have the right to have a representative witness all gauges, tests, and measurements. In the absence of the other Party's representative, such gauges, tests and measurements shall be deemed to be correct. B. WARRANTY: The Seller represents and warrants that: (1) it has good title to all Product sold and/or delivered hereunder, (2) the Product is free from adverse claims of any kind whatsoever, including but not limited to, royalties, liens, encumbrances and all applicable foreign, federal, state and local taxes, (3) the Product has been produced, handled and transported in accordance with all applicable laws, orders and regulations of all governmental authorities, and (4) the Product delivered shall not be contaminated by chemicals foreign to virgin Product including, but not limited to chlorinated and/or oxygenated hydrocarbons and lead. Buyer shall have the right without prejudice to any other remedy available to Buyer, to reject and return to Seller any quantities of Product which are found to be so contaminated, even after delivery to Buyer. Seller shall furnish, at no cost to Buyer, evidence of title satisfactory to Buyer. If Seller receives proceeds hereunder on behalf of, on the account of or interests, overriding royalty interests, production payments, other interests in lands, leases, or production or governmental taxing authorities), it shall promptly make full and proper settlement to each such person or entity. Seller shall defend, indemnify and hold Buyer and its affiliates, directors, officers, employees, agents and harmless from and against any and all claims, liabilities, demands, actions, causes of action, costs, losses, damages, and expenses of every character (including, without limitation, court costs, reasonable attorneys' fees, and costs required to investigate, handle, respond to or defend any such claims, demands, or actions) arising from or in any way relating to adverse claims regarding Seller's title to or ownership of the Product, the proceeds thereof, taxes thereon and/or the lands or leases from which the Product is produced. In the event of any adverse claim to Seller's title to the Product sold and/or delivered hereunder or the proceeds thereof, Buyer may withhold that portion of the proceeds due hereunder reasonably related to such claim, without interest or damages, until such claim is finally determined. SUCH INDEMNIFICATION SHALL APPLY NOTWITHSTANDING BUYER'S NEGLIGENCE OR OTHER ACTIONS AND NOTWITHSTANDING SUCH ACT MAY OCCUR IN THE FUTURE, IT BEING THE INTENT OF THE PARTIES HERETO THAT SUCH INDEMNIFICATION SHALL APPLY TO ALL SUCH ACTS. C. RULES AND REGULATIONS: The terms, provisions and activities undertaken pursuant to this Contract shall be subject to all applicable laws, orders and regulations of all governmental authorities. If at any time a provision hereof violates any such applicable laws, orders or regulations, such provision shall be voided and the remainder of this Contract shall continue in full force and effect unless terminated by either Party upon giving written notice to the other Party hereto. If applicable, the Parties shall comply with all provisions (as amended) of the Equal Opportunity Clause prescribed in 41 C.F.R.60-1.4; the Affirmative Action Clause for disabled veterans and veterans of the Vietnam Era prescribed in 41 C.F.R. 60-250.4; the Affirmative Action Clause for Handicapped Workers prescribed in 41 C.F.R. 60-741.4; 48 C.F.R. Chapter 1 Subpart 19.7 regarding Small Business and Small Disadvantaged Business Concerns; 48 C.F.R. Chapter 1 Subpart 20.3 regarding Utilization of Labor Surplus Area Concerns; Executive Order 12138 and regulations thereunder regarding subcontracts to women-owned business concerns; Affirmative Action Compliance Program (41. C.F.R. 60-1.40; annually file SF-100 Employer Information Report (41 C.F.R. 60-1.7): 41 C.F.R. 60-1.8 prohibiting segregated facilities: and the Fair Labor Standards Act of 1938 as amended, all of which are Incorporated in this Contract by reference. D. HAZARD COMMUNICATION: Seller shall provide its Material Safety Data Sheet ("MSDS") to Buyer. Buyer acknowledges the hazards and risks in handling and using Product. Buyer shall read the MSDS and advise its employees, its affiliates, and third parties, who may purchase or come into contact with such Product, about the hazards of Product, as well as the precautionary procedures for handling Product, which are set forth in such MSDS and any supplementary MSDS or written warning(s) which Seller may provide to Buyer from time to time. 3 E. FORCE MAJEURE: Except for payment due hereunder, either Party hereto shall be relieved from liability for failure to perform hereunder for the duration and to the extent such failure is occasioned by war, riots, insurrections, fire, explosions, sabotage, strikes, and other labor or industrial disturbances, acts of God or the elements, governmental laws, regulations, or requests, disruption or breakdown of production or transportation facilities, delays of pipeline Carrier in receiving and delivering Product tendered, or by any other cause, whether similar or not, reasonably beyond the control of such Party. Any such failures to perform shall be remedied with all reasonable dispatch, but neither Party shall be required to supply substitute quantities from other sources of supply. Failure to perform due to events or Force Majeure shall not extend the terms of this Contract. Notwithstanding the above, and in the event that this Contract is an associated purchase/sale, or exchange of Product, the Parties shall have the rights and obligations described below in the following circumstances: (1) If, because of Force Majeure, the Party declaring Force Majeure (the "Declaring Party") is unable to deliver part or all of the quantity of Product which the Declaring Party is obligated to deliver under this Contract, the other Party (the "Exchange Partner") shall have the right but not the obligation to reduce its deliveries of Product under the same agreement by an amount not to exceed the number of Barrels of Product that the Declaring Party fails to deliver, and (2) If, because of Force Majeure, the Declaring Party is unable to take delivery of part or all of the quantity of Product to be delivered by the Exchange Partner under the agreement, the Exchange Partner shall have the right but not the obligation to reduce its receipts of Product under the agreement by an amount not to exceed the number of Barrels of Product which the Declaring Party fails to take delivery. F. PAYMENT: Unless otherwise specified in this main body of this Contract: (1) Buyer shall make payment against Seller's Invoice for the Product purchased hereunder to a bank designated by Seller in U.S. dollars by telegraphic transfer in immediately available funds, (2) Payments will be due on or before the 20th day of the month following the month of delivery, (3) Payments will be made by wire transfer or other manner agreed upon in writing, (4) If a payment due date is on a Saturday or New York bank holiday other than Monday, payment shall be due on the preceding New York banking day, and if a payment due date is on a Sunday or a Monday New York bank holiday, payment shall be due on the succeeding New York banking day, and (5) All past due payments hereunder shall bear interest from the date due until paid at a rate equal to the lesser of (i) a per annum rate equal to the prime rate of interest charged by Citibank, N.A. (or its successors) plus five percent (5%) or (ii) the maximum nonusurious rate of interest permitted to be charged under applicable law. G. FINANCIAL RESPONSIBILITY: Notwithstanding anything to the contrary in this Contract, should Seller reasonably believe it necessary to assure payment, Seller may at any time require, by written notice to Buyer, advance cash payment or satisfactory security in the form of a Letter or Letters of Credit at Buyer's expense in a form and from a bank acceptable to Seller to cover any of all deliveries of Product. If Buyer does not provide the Letter of Credit on or before the date specified in Seller's notice under this Paragraph G, Seller or Buyer may terminate this Contract forthwith. However, if a Letter of Credit is required under the main body of this Contract and Buyer does not provide same, then Seller only may terminate this Contract forthwith. In no event shall Seller be obligated to schedule or complete delivery of the Product until said Letter of Credit is found acceptable to Seller. Each Party may offset any payments or deliveries due to the other Party under this or any other agreement between the Parties. If a Party (the "Defaulting Party") should (1) become the subject of bankruptcy or other insolvency proceedings, or proceedings for the appointment of a receiver, trustee, or similar official, (2) become generally unable to pay its debts as they become due, or (3) make a general assignment for the benefit of creditors, the other Party may withhold shipments without notice. H. LIQUIDATION: (1) Right to Liquidate. At any time after the occurrence of one or more of the events described in the last sentence of Paragraph G above, the other Party (the "Liquidating Party") shall have the right, at its sole discretion, to liquidate this Contract by terminating this Contract. Upon termination, the Parties shall have no further rights or obligations with respect to this Contract, except for the payment of the amount(s) (the "Settlement Amount" or "Settlement Amounts") determined as provided in Paragraph H(3). (2) Multiple Deliveries. If this Contract provides for multiple deliveries of one or more types of Product in the same or different delivery months, or for the purchase or exchange of Product by the Parties, all deliveries under this Contract to the same Party at the same delivery location during a particular delivery month shall be considered a single commodity transaction ("Commodity Transaction") for the purpose of determining the Settlement Amount(s). If the Liquidating Party elects to liquidate this Contract, the Liquidating Party must terminate all Commodity Transactions under this Contract. (3) Settlement Amount. With respect to each terminated Commodity Transaction, the Settlement Amount shall be equal to the contract quantity of Product, multiplied by the difference between the contract price per Barrel specified in this Contract (the "Contract Price") and the market price per Barrel of Product on the date the Liquidating Party terminates this Contract (the "Market Price"). If the Market Price exceeds the Contract Price in a Commodity Transaction, the selling Party shall pay the Settlement Amount to the buying Party. If the Market Price is less than the Contract in a Commodity Transaction, the buying Party shall pay the Settlement Amount to the selling Party. If the Market Price is equal to the Contract Price in a Commodity Transaction, no Settlement Amount shall be due. 4 (4) Termination Date. For the Purpose of determining the Settlement Amount the date on which the Liquidating Party terminates this Contract shall be deemed to be (a) the date on which the Liquidating Party sends written notice of termination to the Defaulting Party, if such notice of termination is sent by telex or facsimile transaction; or (b) the date on which the Defaulting Party receives written notice of termination from the Liquidating Party, if such notice of termination is given by United States mail or a private mail delivery service. (5) Market Price. Unless otherwise provided in this Contract, the Market Price of Product sold or exchanged under this Contract shall be the price for Product for the delivery month specified in this Contract and at the delivery location that corresponds to the delivery locations specified in this Contract, as reported in Platt's Oilgram Price Report ("Platt's") for the date on which the Liquidating Party terminates this Contract. If Platt's reports a range of prices for Product on that date, the Market Price shall be the arithmetic average of the high and low prices reported by Platt's. If Platt's does not report prices for the Product being sold under this Contract, the Liquidating Party shall determine the Market Price of such Product in a commercially reasonable manner, unless otherwise provided in this Contract. (6) Payment of Settlement Amount. Any Settlement Amount due upon termination of this Contract shall be paid in immediately available funds within two business days after the Liquidating Party terminates this Contract. However, if this Contract provides for more than one Commodity Transaction, or if Settlement Amounts are due under other agreements terminated by the Liquidating Party, the Settlement Amounts due to each Party for such Commodity Transactions and/or agreements shall be aggregated. The Party owing the net amount after such aggregation shall pay such net amount to the other Party in immediately available funds within two business days after the date on which the Liquidating Party terminates this Contract. (7) Miscellaneous. This Paragraph H shall not; limit the rights and remedies available to the Liquidating Party by law or under other provisions of this Contract. The Parties hereby acknowledge that this Contract constitutes a forward contract for purposes of Section 556 of the U.S. Bankruptcy Code. I. EQUAL DAILY DELIVERIES: For pricing purposes only, unless otherwise specified in the main body of this Contract, all Product delivered hereunder during any calendar month shall be considered to have been delivered in equal daily quantities during such calendar month. J. EXCHANGE BALANCING: If volumes are exchanges, each Party shall be responsible for maintaining the exchange in balance on a month-to-month basis, as near as pipeline or other transportation conditions will permit. In all events upon termination of this Contract and after all monetary obligations under this Contract have been satisfied, any volume imbalance existing at the conclusion of this Contract, limited to the total contract volume, will be settled by the underdelivering Party making delivery of the total volume imbalance in accordance with the delivery provisions of this Contract applicable to the underdelivering Party, unless mutually agreed to the contrary. The request to schedule all volume imbalances must be confirmed in writing by one Party or both Parties. Volume imbalances confirmed by the 20th of the calendar month shall be delivered during the calendar month after the volume imbalance is confirmed. Volume imbalances confirmed after the 20th of the calendar month shall be delivered during the second calendar month after the volume imbalance in confirmed. K. DELIVERY, TITLE, AND RISK OF LOSS: For lease delivery locations, delivery of the Product to the Buyer shall be effected as the Product passes the last permanent delivery flange and/or meter connecting the Seller's lease/unit storage tanks or processing facilities to the Buyer's Carrier. For delivery locations other than lease/unit delivery locations, delivery of the Product to the Buyer shall be effected as the Product passes the last permanent delivery flange and/or meter connecting the delivery facility designated by the Seller to the Buyer's Carrier. If delivery is by in-line transfer, delivery of the Product to the Buyer shall be effected at the particular pipeline facility designated in this Contract. Title to and risk of loss of the Product shall pass form the Seller to the Buyer upon delivery. Each Party shall defend, indemnify and hold the other Party and its affiliates, directors, officers, employees, and agents harmless from and against any and all claims, liabilities, demands, actions, causes of action, costs, losses, damages, and expenses of every character (including, without limitation, court costs, reasonable attorney fees and costs required to investigate, handle, respond to or defend any such claims, demands, or actions) relating to the ownership, control and/or handling of the Product while it has risk of loss, except to the extent caused by the other Party's negligence. L. AUDIT: Each Party, on execution of the other's confidentiality agreement, shall have the right to review the records of the other during normal business hours to the extent necessary to verify the accuracy of any statement, charge, computation, or demand made pursuant to this Contract, and shall have the right to obtain payment for, or shall pay, as applicable, any verifiable inaccuracy found; provided, however, any statement shall be final as to the Parties unless questioned within two (2) years of the date of such statement. The sole and exclusive remedy and measure of damages for any improper payments under this Contract shall be the amount of overpayment or underpayment, as the case may be, during the two (2) year period immediately preceding the date on which a statement delivered hereunder was questioned in writing. M. NECESSARY DOCUMENTS: Upon request, each Party shall furnish all substantiating documents incident to the transaction, including a Delivery Ticket for each volume delivered and an Invoice for any calendar month in which the sums are due. 5 N. DIVISION ORDERS: If either Party signs a division order in favor of the other party pertaining to the object of this Contract, the terms of this Contract shall control in the event of any conflict. If under such division order or other agreement: (1) Seller is being disbursed 100% of the proceeds of production, it hereby assumes liability and shall be responsible for payment of any and all proceeds from the sale of production to all rightful owners, including, without limitation, working interest, royalty and overriding royalty interest owners and other payments due or to become due on the production and, if such disbursed proceeds are inclusive of taxes, all taxes applicable to the production, purchase, sale, storage or transportation of production, including, without limitation, severance taxes, to the proper governmental authorities and (2) Seller has requested Buyer to disburse the proceeds of production, Buyer will disburse proceeds as the Seller directs. O. TERMS: Unless otherwise specified in the main body of this Contract, delivery months begin at 7:00 a.m. on the first day of the calendar month and end at 7:00 a.m. on the first day of the following calendar month. P. GOVERNING LAW: This Contract and the performance hereof shall be governed by and construed and enforced in accordance with the laws of the State of Oklahoma, without regard to any conflict of laws provision thereof that would otherwise require the application of the law of any other jurisdiction. THE PARTIES HEREBY WAIVE ANY AND ALL RIGHTS TO DEMAND A TRIAL BY JURY. Q. ATTORNEY'S FEES: In the event litigation arising out of this Contract is initiated by either Party, the prevailing Party, after the entry of a final non-appealable order, shall be entitled to recover from the other Party, as a part of said order, all court costs, fees and expenses of such litigation, including, without limitation, reasonable attorneys' fees. R. DAMAGE WAIVER: Damage Waiver: Only actual damages shall be recoverable under this Contract and the Parties hereby waive any right to recover special, punitive, consequential, incidental or exemplary damages except to the extent any such Party suffers such damages to an unaffiliated third-party in connection with a third-party claim for which a Party is entitled to indemnification hereunder, in which event such damages shall be recoverable. S. WAIVER: No course of dealing and no delay on the part of either Party in exercising any right, power or remedy shall operate as a waiver thereof or otherwise prejudice such Party's rights, powers or remedies. No term or condition of this Contract shall be deemed to have been waived nor shall there be any estoppel to enforce any provision of this Contract except by written instrument of the Parties charged with such waiver or estoppel. The waiver of any breach of any term, condition or provision of this Contract shall not be construed as a waiver of any prior, concurrent or subsequent breach of the same or any other term, condition or provision hereof. T. ASSIGNMENT: This Contract shall inure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns, but neither this Contract nor any of the rights, interests or obligations hereunder shall be assigned by either Party (whether by operation of law, merger, consolidation or otherwise) without the prior written consent of the other Party, such consent not to be unreasonably withheld, conditioned or delayed; provided, however, upon the giving of written notice to the other Party, either Party may assign this Contract to an affiliate of such Party without the consent of the other Party. No assignment of this Contract shall in any way operate to enlarge, alter, or change any right or obligation of the other Party hereto and shall not be effective or binding on the other Party until a copy of the same has been delivered to the other Party. This Contract, including any and all renewals, extensions, amendments and/or supplements hereto, shall be binding upon any purchaser or assignee of the Leases, or any part thereof or interest therein. Any Party assigning its interest shall remain responsible for any nonperformance hereunder. This contract shall constitute a real property right and covenant running with the leases. U. CAPTIONS: The headings of the paragraphs, sections and other subdivisions of this Contract are included for convenience only and shall not constitute part of this Contract or affect the construction or interpretation hereof or thereof. V. AMENDMENTS: This Contract may not be effectively amended, changed, modified, altered or terminated, except as provided herein, without the written consent of the Parties and such consent shall be effective only in the specific instance and for the specific purpose for which it is given. W. NO THIRD PARTY BENEFICIARIES: This Contract shall be only for the benefit of the parties hereto and their respective legal representatives, successors and permitted assigns, it being the intention of the parties hereto that no third party shall be deemed a third party beneficiary of this Contract. 6 X. ENTIRE AGREEMENT: This Contract contains the entire agreement of the Parties. This Contract may not be contradicted by evidence of prior, contemporaneous or subsequent oral agreements of the Parties. There are no oral agreements between the Parties. Y. SURVIVAL: Any obligation owed by a Party to the other Party under this Contract, including indemnification obligations, shall survive termination of this Contract. Z. DEFINITIONS: Unless the context requires otherwise, terms defined in the text of this Contract shall have the meaning indicated and the terms listed below have the following meanings: "API" means the American Petroleum Institute. "ASME" means the American Society of Mechanical Engineers. "ASTM" means the American Society for Testing Materials. "Barrel" means 42 U.S. gallons of 231 cubic inches per gallon corrected to 60 degrees Fahrenheit. "Carrier" means a pipeline, barge, truck or other suitable transporter of Product. "Product" means crude oil or condensate, as appropriate. "Delivery Ticket" means a shipping/loading document or documents stating the type and quality of Product delivered, the volume delivered and method of measurement, the corrected specific gravity, temperature, and S&W content. "Invoice" means a statement setting forth at least the following information: The date(s) of delivery under the transaction: the location(s) of delivery; the volume(s); price(s); the specific gravity and gravity adjustments to the price(s) (where applicable); and the term(s) of payment. "S&W" means sediment and water EX-10.16 7 d85560ex10-16.txt CRUDE OIL PURCHASE CONTRACT-EOTT ENERGY OPERATING 1 EXHIBIT 10.16 [EOTT ENERGY OPERATING LIMITED PARTNERSHIP LETTERHEAD] December 19, 2000 CRUDE OIL PURCHASE CONTRACT Coho Resources, Inc. 14785 Preston Road Suite 865 Dallas, Texas 75240 Attn: Mr. Gary Pittman Chief Financial Officer Re: EOTT CONTRACT NO. TP00-1018776 COHO CONTRACT NO. ____________ Gentlemen: When accepted by you in the manner hereinafter indicated, this shall evidence the agreement ("Agreement") by and between COHO RESOURCES, INC., hereinafter referred to as "COHO", and EOTT ENERGY OPERATING LIMITED PARTNERSHIP, hereinafter referred to as "EOTT", under the terms of which, and in consideration of the promises made hereunder and for other valuable consideration received, such parties shall sell and buy the hereinafter described crude oil and/or condensate ("crude oil") as follows: I. TERM: Commencing at 7:00 a.m. Central Time on November 1, 2000 to 7:00 a.m. Central Time on December 31, 2001. Termination shall not affect rights or obligations of either party accrued prior to the date of termination. II. TYPE OF OIL: Subject to the terms hereof, COHO shall deliver to EOTT COHO's owned or controlled production of Mississippi Light Sweet, Mississippi Light Sour and Mississippi Heavy Sour types of crude oil as listed on Attachment "A" hereto. III. QUANTITY: Volume to fluctuate with COHO's production from the Leases or Units listed on Attachment "A." Production from the properties listed on Attachment "A" currently averages eight thousand (8,000) barrels per day. A-l 2 IV. DELIVERY: COHO shall deliver to EOTT at various lease sites, per Attachment "A", by tank gauges and/or meters into EOTT's designated carrier(s) with title and risk of loss to pass to EOTT as the oil passes through the outlet flange of COHO's tankage and/or meters. If Attachment "A" does not list all applicable leases, said leases shall nevertheless be covered hereunder and the parties hereto shall amend Attachment "A" as needed. V. PRICE: For each barrel of crude oil delivered to EOTT hereunder during each calendar month, EOTT shall pay EOTT's average daily posted price for the applicable calendar month, with adjustment made for gravity delivered, plus the applicable per barrel premium, as per Attachment "A" incorporated herein and made a part hereof for all purposes. For pricing purposes, all crude oil delivered hereunder during any calendar month will be considered to have been delivered in equal daily quantities during each such month. VI. PAYMENT: Payment shall be made by EOTT by open division order, less applicable production and severance taxes, by check, except COHO shall receive payment for its interest by wire transfer on the twentieth (20th) day of the calendar month following the calendar month of delivery. VII. DIVISION ORDERS: All division orders, division order documents and division order matters shall be sent to the following addresses: EOTT Energy Operating Limited Coho Resources, Inc. Partnership Attn: Division Order Department Attn: Division Order Department 14785 Preston Road, Suite 860 P.O. Box 4666 Dallas, Texas 75240 Houston, TX 77210-4666 If any division orders are executed pursuant to this Agreement, and in the event of any irreconcilable conflict between the terms of any such division orders and this Agreement, the terms of this Agreement shall be deemed controlling, even if the division orders are dated subsequent to this Agreement. VIII. SPECIAL PROVISIONS: (A) COHO shall fully defend and indemnify EOTT against, and hold EOTT fully harmless from, any claim, action, suit, demand or complaint (of any nature whatsoever) which any interest owner in any well (on any lease which is covered or affected hereby) may bring in connection with (i) COHO's ability to enter into this Agreement with EOTT, or (ii) any production proceeds paid out by EOTT to COHO pursuant to this Agreement. COHO warrants unto EOTT that COHO has full right and authority to enter into this Agreement for all of the crude oil committed by COHO hereunder, and that COHO is violating no duty or obligation which it may have to any third party in entering into this Agreement, provided, however, EOTT acknowledges that under certain agreements between COHO and other working interest owners COHO's authority to market crude oil is limited to periods not exceeding one year, but EOTT may rely upon COHO's authority to market in the case of any and all crude oil actually delivered to EOTT hereunder. (B) All crude oil delivered to EOTT hereunder will be crude oil delivered in accordance with the quality standards set forth herein (including the General Provisions attached hereto), and COHO will fully indemnify EOTT against and hold EOTT harmless from any loss, damage, harm, liability, claim, action, suit, demand or complaint, of any nature whatsoever, which EOTT may A-2 3 suffer as a result of receiving non-standard crude oil from COHO at the point of title transfer set forth herein as a consequence of COHO's intentional addition in such crude oil of any contaminant. (C) This Agreement is subject to the General Provisions which are attached hereto and made a part hereof for all purposes. IX. ADDITIONAL LEASE PRODUCTION: EOTT agrees that any production which is subsequently owned, developed, controlled, or acquired by COHO where COHO has the right to market the production, in the State of Mississippi during the Term of this Agreement shall be automatically added to this Agreement, provided the said production is a type of crude oil then being purchased by EOTT and is located in an area from which EOTT then makes crude oil purchases. The pricing for any additional production added to this Agreement under this Paragraph IX shall be priced according to crude oil grade as follows: (i) For Mississippi Light Sweet type crude oil: EOTT's posted price for South Louisiana Sweet, with adjustment made for gravity delivered, plus $1.50 per barrel premium, based on deemed equal daily deliveries during each calendar month. (ii) For Mississippi Light Sour type crude oil: EOTT's posted price for Mississippi Light Sour, with adjustment made for gravity delivered, plus $1.70 per barrel premium, based on deemed equal daily deliveries during each calendar month. (iii) For Mississippi Heavy Sour type crude oil transported by pipeline: EOTT's posted price for Mississippi Light Sour, with adjustment made for gravity delivered, plus $1.70 per barrel premium, based on deemed equal daily deliveries during each calendar month. For Mississippi Heavy Sour type crude oil transported by truck: EOTT's posted price for Mississippi Light Sour, with adjustment made for gravity delivered, plus $1.00 per barrel premium, based on deemed equal daily deliveries during each calendar month. X. OTHER PRODUCTION: COHO also grants EOTT the right of first refusal to purchase any "other" production which is owned, developed, controlled, or acquired at any time by COHO where COHO has the right to market the production in the states of Mississippi or Alabama during the Term of this Agreement (meaning any crude oil type which is not being purchased by EOTT or any crude oil in any area from which EOTT does not make crude oil purchases). The notice period for the right of first refusal shall be for a period of thirty (30) days from the date EOTT receives notice from COHO of any offers. As to such "other" production, EOTT shall have the right, but not the obligation, to add same to this Agreement. The price structure for any other grade of Mississippi crude oil or for any additional crude oil production in the State of Alabama which becomes subject to this Agreement shall be negotiated at the time of COHO's acquisition of such production. In the event EOTT and COHO cannot agree upon the applicable pricing structure for any such production, the matter shall be submitted to arbitration for binding resolution. XI. RIGHT TO SWITCH PRICING METHOD: Reference is made to the one-time right to switch the pricing method (which is described in parts I, II and III of Attachment "A"). Subject to the same timing and other requirements set forth in Attachment "A," COHO shall have the same, one-time right to switch the pricing method as to each of the crude types set forth in Paragraphs IX(i), IX(ii), and IX(iii) above, as follows: A-3 4 (a) For the Mississippi Light Sweet type crude covered under Paragraph IX(i) above, COHO may elect to switch the pricing to the average of Plains Marketing's and EOTT's daily posted prices for Louisiana Light Sweet crude oil during the applicable calendar month of delivery hereunder, with adjustment made for gravity delivered, plus $1.50 per barrel. (b) For the Mississippi Light Sour type crude covered under Paragraph IX(ii) above, COHO may elect to switch the pricing to the average of Equiva's and EOTT's daily posted prices for Mississippi Sour crude oil during the applicable calendar month of delivery hereunder, with adjustment made for gravity delivered, plus $1.70 per barrel. (c) For the Mississippi Heavy Sour type crude covered under Paragraph IX(iii) above, COHO may elect to switch the pricing to the average of Equiva's and EOTT's daily posted prices Mississippi Sour crude oil during the applicable calendar month of delivery hereunder, with adjustment made for gravity delivered, plus $1.70 per barrel for those barrels gathered by pipeline or plus $1.00 per barrel for those barrels gathered by truck. This one-time right to switch the pricing method shall be exercisable by thirty (30) days' written notice from COHO to EOTT, to be effective on the first day of any calendar month after the notice period as designated by COHO in such notice. XII. RENEWAL TERMS: Prior to the expiration of this Agreement, EOTT and COHO shall endeavor to negotiate a new, mutually-agreeable agreement, or a mutually-agreeable extension of this Agreement. Should the parties be unable to agree upon the terms for a new agreement or an extension, or should COHO notify EOTT that it does not wish to negotiate a new agreement or an extension, EOTT and COHO shall be bound by the following terms and conditions: (i) COHO shall solicit bonafide competitive bids from other purchasers (unrelated to COHO) for purchases to be made on or after January 1, 2002, and EOTT shall have the right and option, but not the obligation, to match any bonafide written offer (from any bonafide crude oil purchaser) which COHO will otherwise act upon. COHO shall submit any such bonafide written offer to EOTT no later than December 1, 2001, and EOTT shall advise COHO, no later than December 19, 2001, as to whether EOTT will match such written offer. (ii) If COHO proceeds under Paragraph XII(i) above, and if EOTT elects not to match an applicable bonafide written offer from a bonafide crude oil purchaser, EOTT shall, at COHO's option, enter into a buy/sell agreement with COHO whereby EOTT shall purchase a volume and quality of Mississippi/Alabama crude oil equal to the lease production covered under this Agreement as of December 31, 2001, and sell back to COHO a corresponding volume of crude oil of the grade(s) and quality(ies) provided below. Such delivery back to COHO shall be at either Genesis Pipeline Company's Liberty, Mississippi Station or within TEPPCO Pipeline's facilities at Cushing, Oklahoma, or any combination of these locations, at COHO's option. In the case of deliveries back to COHO at Genesis Pipeline Company's Liberty, Mississippi Station, EOTT shall deliver back to COHO substantially the same grades and qualities of crude oil as are delivered by COHO to EOTT in the applicable calendar month. In the case of deliveries back to COHO within TEPPCO Pipeline's facilities at Cushing, Oklahoma, EOTT shall deliver back to COHO West Texas Intermediate type crude oil. All deliveries made by EOTT to COHO shall be subject to location differentials (in favor of EOTT) and shall be established when the buy/sell agreement is negotiated, with binding arbitration to be used if such differentials cannot be agreed upon. Subject to the location differentials described in the preceding sentences of this Paragraph XII(ii), (a) pricing for all deliveries made by COHO to EOTT pursuant to the buy/sell agreement shall be based upon mutually-agreeable area posted prices for the grades and qualities of crude oil delivered by COHO to EOTT thereunder, (b) pricing for all deliveries made by EOTT back to A-4 5 COHO at Genesis Pipeline Company's Liberty, Mississippi Station pursuant to the buy/sell agreement shall be based upon the same posted prices determined in accordance with part (a) of this sentence, and (c) pricing for all deliveries made by EOTT back to COHO within TEPPCO Pipeline's facilities at Cushing, Oklahoma pursuant to the buy/sell agreement shall be based upon mutually-agreeable posted prices for West Texas Intermediate type crude oil. If agreement cannot be reached on a specific posted price, then an average of all market related area posted prices for grade and quality of oil delivered shall be used. XIII. ARBITRATION: Wherever in this Agreement a provision is made for resolution of a disagreement between the parties by arbitration, such arbitration proceedings shall be conducted in accordance with the commercial arbitration rules, then in effect, of the American Arbitration Association. All such arbitration proceedings shall be conducted in Houston, Texas unless otherwise agreed upon by the parties. XIV. ASSIGNABILITY: This Agreement, or any portion thereof, shall not be assignable by either party without the prior written consent from the other party, which consent shall not be unreasonably withheld. No assignment shall be binding on either party unless and until the other party has received written notice of the assignment and provided its written consent. XV. NO PARTNERSHIP OR JOINT VENTURE: Nothing contained herein is intended to constitute a partnership or joint venture between the parties. If the foregoing accurately reflects our agreement, please execute this document in the space provided below and return a fully executed counterpart hereof to EOTT for its files. Sincerely, EOTT ENERGY OPERATING LIMITED PARTNERSHIP By: EOTT Energy Corp., its General Partner By: /s/ DAN E. COLE ----------------------------------------- Dan E. Cole General Manager Gulf Coast Region ACCEPTED AND AGREED TO THIS 18TH DAY OF JANUARY, 2001 BY: COHO RESOURCES, INC. By: /s/ GARY L. PITTMAN ------------------------------------------ Title: CFO --------------------------------------- A-5 EX-21.1 8 d85560ex21-1.txt SUBSIDIARIES OF THE REGISTRANT 1 EXHIBIT 21.1 COHO ENERGY, INC. LIST OF SUBSIDIARIES Coho Resources Limited, Alberta, Canada (100% subsidiary of Coho Energy, Inc.) Coho Resources, Inc., Nevada (owned .1% by Coho Resources Limited and 99.9% by Coho Energy, Inc.) Coho Marketing & Transportation, Inc., Nevada (100% subsidiary of Coho Resources, Inc.)* Coho Shell Company, Delaware (100% subsidiary of Coho Energy, Inc.) Profile Petroleum Ltd., Alberta, Canada (100% subsidiary of Coho Resources Limited) Grayon Development Limited, Alberta, Canada (100% subsidiary of Coho Resources Limited) Coho International Limited, Bahamas (100% subsidiary of Coho Resources Limited) Coho Anaguid, Inc., Delaware (100% subsidiary of Coho Resources, Inc.) Interstate Natural Gas Company, Delaware (100% subsidiary of Coho Resources, Inc.)* Coho Exploration, Inc., Delaware (100% subsidiary of Interstate Natural Gas Company)* Coho Louisiana Production Company, Delaware (100% subsidiary of Interstate Natural Gas Company)* Coho Oil & Gas, Inc., Delaware (100% subsidiary of Coho Resources, Inc.) * These subsidiaries were merged into Coho Resources, Inc. effective December 31, 2000. -----END PRIVACY-ENHANCED MESSAGE-----