If this Form is filed to register additional securities for an offering pursuant to Rule 462 (b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [_]

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CALCULATION OF REGISTRATION FEE

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to Section 8(a) of the Securities Act, may determine.

TABLE OF CONTENTS

We currently plan on drilling 75 wells in 2000. In addition, we plan to continue drilling, development and strategic acquisition activities primarily for our own account which should enable us to expand our activities and operations. We believe our business plan will result in the continued growth of our proved natural gas and oil reserves, net cash

Summary Natural Gas and Oil Reserve Information

Energy Search oil and natural gas reserves are located in Ohio and West Virginia. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate to be reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells using existing equipment and operating methods. Proved undeveloped reserves are proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells at depths below the present bottom of the wells.

The following table summarizes information with respect to the estimated net proved oil and natural gas reserves as reviewed, evaluated and certified by Wright & Company, Inc., independent certified petroleum engineers, attributable to our interests in oil and natural gas properties as of December 31, 1999, 1998 and 1997.

The oil and natural gas reserve amounts in the following table represent well interests and reserves directly owned 100% by Energy Search. No reserves shown below as owned by Energy Search are owned indirectly through any limited partnership.

TOTAL ESTIMATED NET RESERVE QUANTITIES

The following table represents the estimated future net revenues and the present value of the future estimated net reserves discounted at a rate of 10% per year from the proved developed producing, proved developed non-producing and proved undeveloped reserves of Energy Search as of December 31, 1999, 1998 and 1997, respectively.

With respect to the table below, the estimated discounted present value of future net cash flows from proved oil and gas reserves is computed assuming a constant net price of $23.25 per barrel of oil and $3.25 per Mcf of natural gas for all fields except the Mitchell field acquired from Mitchell Energy, which is computed using a gas price of $3.00. For the fiscal year ended December 31, 1999, we received gross oil prices ranging from $9.38 to $23.50 per barrel and gross natural gas prices ranging from $1.65 to $3.47 per Mcf before royalties and gathering and transportation costs.

For additional information concerning the discounted future net cash flows to be derived from our reserves, see the Supplemental Information to Consolidated Financial Statements included in this amended Prospectus.

In accordance with applicable requirements of the Securities and Exchange Commission, estimates of our proved reserves and future cash flows are made using sales prices estimated to be in effect as of the date of the reserve estimates and are held constant throughout the life of the properties, except to the extent a contract specifically provides otherwise. Estimated quantities of proved reserves and future cash flows therefrom are affected by natural gas and oil prices, which have fluctuated widely in recent years.

While we believe that reserve estimates presented in this Prospectus are reasonable, the estimates should be viewed with the understanding that subsequent reservoir performance, the timing and success of future development drilling and changes in pricing structure or market demand will affect the reserve estimates.

Summary Financial Information

The following summary of historical consolidated financial information of Energy Search for the years ended December 31, 1999 and 1998 has been derived from our audited Consolidated Financial Statements and the notes thereto contained in the Annual Report on form 10-KSBA filed with the SEC for the fiscal year ended December 31, 1999. The data presented for the three months ended March 31, 2000, is derived from our unaudited Consolidated Financial Statements and the notes thereto contained in the Quarterly Report on Form 10-QSB filed with the SEC for the quarterly period ended March 31, 2000.

Risk Factors

An investment in Energy Search common stock or Series A Warrants involves a high degree of risk. Prospective investors should consider the following factors in addition to the other information set forth in this Prospectus before making an investment decision.

Risks Associated with Energy Search

Development of Additional Reserves. Our future success depends upon our ability to find or acquire additional natural gas and oil reserves that are economically recoverable. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, the proved reserves of Energy Search will generally decline as reserves are produced. There can be no assurance that we will be able to discover and exploit additional commercial quantities of oil and gas, or that we will have success drilling productive wells or acquiring underdeveloped properties at low finding costs.

Need for Additional Financing. Development of our oil and gas properties and execution of our business plan may require capital resources greater than those currently available to us. Current arrangements for additional sources of capital include our credit facility with Southern Producer Services LP (the "SPS Credit Facility"), and net cash flow from operations. There can be no assurance that these, or any other, sources of capital will be available to us on acceptable terms, or at all, in the future. The inability to obtain additional financing would have a material adverse effect on Energy Search, including requiring us to curtail significantly or farm-out development of our oil and natural gas properties. Any additional financing may involve dilution to our existing shareholders.

Dependence on Key Personnel. Our success depends to a large extent on the abilities and continued participation of certain key employees, including Charles P. Torrey, Jr., our chief executive officer, Richard S. Cooper, our president, Robert L. Remine, our secretary and treasurer, and John M. Johnston, our vice president - exploration and production. The loss of any of these officers or other key employees could have a material adverse effect on our business. In an effort to address this risk, we have entered into written employment contracts (which include confidentiality and non-competition clauses) and purchased "key man" term life insurance policies with respect to these officers. In addition, we have adopted a stock option and restricted stock plan through which can provide incentive awards for these individuals. See "Management."

Geologist's Estimates of Reserves and Future Net Revenue. This Prospectus contains estimates of our oil and natural gas reserves and the future net revenues therefrom which have been prepared by a certified independent geologist. See "Business and Properties--Description of Property--Oil and Natural Gas Reserves." These estimates are based on various assumptions and, therefore, are inherently imprecise indications of future revenues. Actual future revenues, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from the estimates. In addition, our reserves may be subject to downward or upward revision, based on production history, results of future exploration and development, prevailing oil and gas prices and other factors.

Undeveloped Acreage May be Lost. Our oil and gas leases typically require the drilling of wells, payment of minimum royalties or delay rentals or the continued production of oil or gas in commercial quantities in order for the leases to remain valid and not lapse. Typically, once a well is drilled and becomes commercially productive, as long as commercial production from such lease continues, the lease will not lapse and is deemed to be "held by production." Nonetheless, lease termination or expiration clauses are specific to each lease. If existing and future drilling commitments, minimum royalty payments or continuing production clauses in particular leases are not met, we may lose lease acreage.

Properties Pledged to Secure Debt. All of our oil and gas properties are pledged to secure the SPS Credit Facility and our non-oil and gas properties are pledged to SunTrust Bank. A failure to pay the principal or accrued interest on such secured obligations could cause us to lose our interest in our principal properties. For further information on these secured transactions, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes to Consolidated Financial Statements included herein.

Accumulated Deficit. As of March 31, 2000, we had an accumulated deficit of $5,921,808. Our future operating results will depend on many factors some of which are beyond our control. There can be no assurance that we will be able to operate profitably in the future.

Limited Diversification of Energy Search's Activities and Properties. We are engaged exclusively in the business of exploration for and production and marketing of natural gas and oil. A large part of our field operations and activities are located in southeastern Ohio, and in southern West Virginia. See "Business and Properties-- Properties--Leasehold Acreage." It is likely that, for the foreseeable future, our activities and primary area of field operations will not change materially.

Risks Associated with the Oil and Gas Industry

Risk of Oil and Gas Operations. Our operations are subject to all of the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blowouts, cratering and fires, which could result in personal injuries, loss of life, pollution damage and other damage to the properties of Energy Search or others. Oil and gas operations present risks of environmental contamination from drilling operations and leakage from oil field storage or transportation facilities. We have never experienced a significant environmental mishap, but spills of oil and other liquids could occur which could create material liability to us for clean-up expenses. See "Business and Properties--Insurance" for a discussion of Energy Search's insurance coverage.

Current Oil and Gas Markets. There is substantial uncertainty as to the prices at which natural gas and oil produced by Energy Search may be sold, and it is possible that under some market conditions the production and sale of oil and gas from some or all of our wells may not be economical. The average natural gas prices we received were $2.43, $2.41 and $2.49 per Mcf in 1997, 1998 and 1999, respectively, prior to reduction for royalties, severance taxes and gathering and transportation charges. The average oil prices we received were $18.06, $11.74 and $19.73 per Bbl in 1997, 1998 and 1999, respectively. The average price received by us for natural gas and oil as of March 31, 2000 has been $2.87 per Mcf and $27.85 per Bbl, respectively. The availability of a ready market for oil and gas and the prices obtained for oil and gas depend upon numerous factors beyond our control, including competition from other natural gas and oil suppliers and national and international economic and political developments. We are not subject to any gas price controls.

Exploration and Development Risks. Exploration and development drilling activities are subject to greater risks of failure than those associated with the ownership of producing properties. The drilling of exploratory wells involves the greatest risks, since such wells are located in unproved areas. The drilling of development wells, although generally consisting of drilling in proven areas, may result in dry holes or the failure to produce natural gas and oil in commercial quantities. The drilling of development wells and exploratory wells also involves the risk that unusual or unexpected formations and pressures will be encountered, and other conditions will exist, that could result in us incurring substantial losses as well as liabilities to third parties or governmental entities.

Operating Hazards and Uninsured Risks. Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by Energy Search will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating, allocable overhead and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.

Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, uncontrollable flows of oil, natural gas or well fluids, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to properties of Energy Search and others. We maintain insurance against some but not necessarily all of the risks described above. In particular, the insurance we maintain does not cover claims relating to failure of title to oil and natural gas leases, trespass during survey acquisition or surface change attributable to seismic operations and, except in limited circumstances, losses due to business interruption. We may elect to self-insure if management believes that the cost of insurance, although available, is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.

Competition and Markets. The oil and natural gas industry is highly competitive. We compete with many other companies in the search for and acquisition of oil and natural gas properties and leases for exploration and development, and also compete with other companies in our activities as drilling contractor and natural gas marketers. Our competitors include numerous independent oil and natural gas companies, major integrated oil and natural gas companies, individuals and drilling and income programs. Many of these companies have substantially greater financial, technical and other resources than us and have been engaged in the exploration and production business for a much longer time than we have. Such companies may be able to pay more for leases on oil and natural gas properties and exploratory prospects, as well as to define, evaluate, bid for or purchase a greater number of properties and prospects than our financial or human resources would permit. We will be required to maintain and enhance our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Competition among oil and gas companies for favorable oil and natural gas prospects can be expected to continue. It is anticipated that the cost of acquiring oil and natural gas properties may increase appreciably.

In the area of capital formation, we compete for investor capital in the public and private equity markets with other oil and gas companies, as well as companies from other industries. We also compete with a number of other companies which offer interests in drilling partnerships with a wide range of investment objectives and program structures. Competition for investment capital from both public and private sources is intense. Our business plan requires that we continue to raise capital for drilling and acquisition activities. Our ability to attract investment capital cannot be assured.

Competition from Alternative Energy Sources. Substantially all of our reserves are natural gas reserves. Natural gas competes with coal, oil, propane, butane, nuclear power and other fuels in the heating and energy generation markets. Numerous factors, all difficult to predict, affect the relative desirability or demand at any point in time for any given fuel. The extent to which public or legislative initiatives to develop and use alternative fuels will, in the future, affect the demand for oil or natural gas cannot be predicted at this time.

Industry Conditions. In recent decades, there have been periods of worldwide over-production and under-production of hydrocarbons as well as periods of increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and, to a lesser extent, natural gas. The excess or short supply of crude oil and natural gas has placed pressures on prices and has resulted in dramatic price fluctuations.

Shut-In Wells and Curtailed Production. In the past, production from oil and natural gas wells (particularly natural gas wells) in many geographic areas of the United States had been curtailed due to lack of market demand, and it is possible that such curtailments may resume in the future. Therefore, it is possible that our wells may have to be shut-in or that oil or gas produced from the wells may have to be sold at less than favorable prices. Production also may be delayed or wells shut-in in the event there is difficulty in securing markets for production, logistical problems develop in the transportation of natural gas from the wells or there are title problems associated with the drill sites. Although it is anticipated that a substantial amount of natural gas from our Ohio wells will be sold to our affiliated Pipeline Operating Partnership, the agreement regarding the gathering and marketing of natural gas

General Regulation. Oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, because such rules and regulations frequently are amended or interpreted, we are unable to predict the future cost or impact of complying with such laws.

State Regulation. Natural gas and oil operations are regulated by an agency of state government in every state of the United States. Many state authorities require permits for drilling operations, drilling bonds and reports concerning operation and impose other requirements relating to the exploration and production of oil and gas. Some states also have statutes or regulations addressing conservation matters, including provisions for the pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations also may limit the rate at which oil and gas can be produced from certain properties. In Ohio and West Virginia, where most of our natural gas and oil properties are located, such regulation is by the Ohio Department of Natural Resources and the West Virginia Division of Environmental Protection Office of Oil and Gas, respectively. Each of these agencies has been granted broad regulatory and enforcement powers which are likely to create additional financial and operational burdens on natural gas and oil operations like those of Energy Search. Ohio and West Virginia also have in place other pollution and environmental control laws which have become increasingly burdensome in recent years.

Federal Regulation. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The Federal Energy Regulatory Commission ("FERC") regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which oil and natural gas can be sold. While sales by producers of natural gas, and all sales of oil and natural gas liquids currently can be made at uncontrolled market prices, Congress could reenact price controls in the future.

In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order 636, issued in April 1992, and its progeny, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or "unbundled" from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services.

Environmental Regulation. Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend likely will continue. These laws and regulations may

The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and comparable state statutes impose strict, joint and several liability on certain classes of persons who are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA such persons or companies may be liable for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the neighboring land owners and other third parties to file claims for personal injury, property damage and recovery of response costs allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial civil and criminal penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations impose clean-up liability relating to petroleum and petroleum-related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

We have acquired leasehold interests in numerous properties that for many years have produced oil and natural gas. Although we believe that the previous owners of these interests used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Notwithstanding our lack of control over properties operated by others, the failure of the operator to comply with applicable environmental regulations may, in certain circumstances, adversely impact us.

The Federal Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. With respect to certain of our operations, we are required to maintain such permits or meet general permit requirements. The Environmental Protection Agency ("EPA") has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. We believe that we will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on us.

Risks Associated with Investment in Energy Search

No Assurance of Public Market; Possible Volatility of Common Stock Prices; Disclosure Relating to Low-Priced Stock. Since January 24, 1997, Energy Search's common stock has been traded on the Nasdaq SmallCap Stock Market under the symbol "EGAS." There can be no assurance that a trading market for our common stock will be sustained. The absence of a trading market may render an investor unable to liquidate his or her investment in Energy Search. The trading price for the common stock may be significantly affected by such factors as the operating results of Energy Search, the United States and global economic conditions and various other factors generally affecting the oil and gas products industry. Additionally, the stock market has from time to time experienced extreme price and volume fluctuations that have particularly affected the market price for small and emerging growth companies. These extreme fluctuations, which often have been unrelated to the operating performance of any particular company or to any group of companies, may adversely affect the market price of our common stock. Energy Search common stock has also been approved for listing on the Boston Stock Exchange under the symbol "EYS." If, at any time, our securities are not quoted on a stock exchange, our securities could become subject to the "penny stock rules" adopted pursuant to Section 15(g) of the Securities Exchange Act of

Dividend Policy. We have not paid or declared any cash dividends with respect to our common stock, nor do we anticipate any such payments or declarations in the foreseeable future. Any future dividends will be declared at the discretion of our Board of Directors and will depend, among other things, on our earnings, if any, our financial requirements for future operations and growth, and such other factors as we may then deem appropriate. Prospective investors should not rely on the receipt of dividends in the near future or at any time in the future when evaluating the merits of an investment in our securities. See "Dividend Policy."

Dilution. The principal shareholders of Energy Search have acquired common stock at a cost per share that is substantially less than that at which we sold the common stock included in the Units to investors in the IPO. In the event that we issue additional common stock in the future, including shares that may be issued upon the exercise of our Series A Warrants, upon the conversion of any 9% redeemable convertible preferred stock issued by Energy Search, or upon issuance of common stock to pay dividends on our 9% preferred stock in the event our registration statement concurrently filed with the SEC goes effective, common stockholders may experience further dilution in the net tangible book value per share of the common stock of Energy Search.

Warrants to Representatives. At completion of the IPO, we sold to the managing underwriters (the "Representatives"), for nominal consideration, Representatives' Warrants to purchase 100,000 Units. To the extent that the Representatives' Warrants are exercised, they would dilute the percentage of outstanding shares held by common stockholders. The exercise of the Representatives' Warrants may occur at a time when we might be able to obtain additional equity capital on terms more favorable than those provided by the Representatives' Warrants.

Use of Proceeds

We intend to use the proceeds realized from paying dividends on our preferred shares in common stock instead of cash for general operating purposes. These purposes include the development and drilling up of oil and gas properties as well as the selective acquisitions of oil and natural gas properties, acquisitions of other companies engaged in the same business as Energy Search, or acquisitions of assets or businesses which Energy Search considers to be complimentary to our core businesses. As of the date of this Prospectus, no specific assets or businesses have been identified for acquisition.

Dividend Policy

Energy Search has never paid, cash dividends on our common stock. We have no current plans to change this policy. We intend to retain all earnings to support our operations and future growth. The payment of any future dividends will be determined by Energy Search board of directors based upon our earnings, financial condition and cash requirements, possible restrictions in future financing agreements, business conditions and other relevant factors. See "Risk Factors--Risks Associated with Investment in Securities--Dividend Policy."

Management's Discussion and Analysis of Financial Condition and Results of Operations

Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

This amended Prospectus contains statements that are not historical facts. These statements are called "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. These statements involve important known and unknown risks, uncertainties and other factors and can be identified by phrases using "estimate," "anticipate," "believe," "project," "expect," "intend," "predict," "potential," "future," "may," "should" and similar expressions or words. Our future results,

This list provides examples of factors that could affect the results described by forward-looking statements contained in this amended Prospectus. However, this list is not intended to be exhaustive; many other factors could impact our business and it is impossible to predict with any accuracy which factors could result in which negative impacts. Although we believe that the forward-looking statements contained in this amended Prospectus are reasonable, we cannot provide you with any guarantee that the anticipated results will be achieved. All forward-looking statements in this amended Prospectus are expressly qualified in their entirety by the cautionary statements contained in this section and you are cautioned not to place undue reliance on the forward-looking statements contained in this amended Prospectus. In addition to the risks listed above, other risks may arise in the future, and we disclaim any obligation to update information contained in any forward-looking statement.

Overview

We are an independent oil and gas company organized as a Tennessee corporation in 1990 and engaged in and focused exclusively on the exploration, development, production and acquisition of natural gas properties and, to a limited extent, oil in the Appalachian Basin. We initially drilled wells primarily for affiliated drilling partnerships and retained only a small portion. During the last several years, we have grown primarily through opportunistic acquisitions of Appalachian properties for our own account, the roll-up of affiliated drilling partnerships and the subsequent drilling development, exploitation and exploration of these properties, resulting in significant increases in our reserves and production. In 1999, approximately 90% of our production was natural gas.

In January 1997, we shifted our focus from being primarily a driller-operator for limited partnerships in which we took a small working interest to an independent energy company developing reserves for our own account. Management believes that this strategic shift has begun to improve our financial condition and results of operations. Daily net paid production for 1999 was approximately 3.6 MMcfed and current production exceeds 6.0 MMcfed.

Our future growth is expected to be driven by development, exploitation and controlled exploration drilling on our existing properties and the continuation of an opportunistic acquisition strategy in the Appalachian Basin region. We have over 400 developmental well sites to drill on existing leasehold acreage. Most of these sites are located in fields with established production histories.

In June of 1999, we entered into a credit financing transaction with Southern Producer Services, L.P. of Houston, Texas. This SPS Credit Facility has a credit limit of $30,000,000, upon which $21,846,358 was drawn down as of March 31, 2000. The SPS Credit Facility is collateralized by a first lien on all of our oil and natural gas properties. Interest is payable at 11% per annum and Southern Producer receives a 3% overriding royalty interest on all of our oil and gas production. We pay interest only on the SPS Credit Facility until July of 2000, at which time certain principal payments become due under an amortization schedule. We have used the proceeds of the SPS Credit Facility principally to retire approximately $8,769,776 in bank debt, to acquire oil and gas properties and to fund the

In connection with the SPS Credit Facility, we granted 100,000 common stock purchase warrants to Southern Producer. These warrants are exercisable at any time until June 23, 2004 at an exercise price of $6.50 per warrant share, subject to downward adjustment if we issue stock in a transaction for less than $6.50 per share, in which case the exercise price will be the same as the lower issue price. We must issue additional warrants to Southern Producer to prevent dilution if we split our stock, declare a stock dividend, recapitalize our company, engage in a business combination or issue new common stock in any other transaction.

In March of 2000, we closed the purchase of approximately 6,500 acres of oil and gas properties from Cabot Oil & Gas Corporation. The property is contiguous to our existing field in Raleigh County, West Virginia and includes 45 producing wells and related gas gathering equipment. We estimate this acquisition will increase production approximately 500 Mcfe per day. We funded the purchase of these properties with proceeds from our Southern Producer credit facility. The effective date of this purchase was January 1, 2000. In connection with this financing, we issued 105,000 shares of common stock to Southern Producer.

In January 2000, we retained the investment banking firm of McDonald Investments Inc., to explore strategic alternatives to maximize shareholder value.

In a transaction completed in February 2000, we issued 15,000 shares of our 9% redeemable convertible preferred stock to limited partners in the Energy Search Natural Gas 1998 L.P., which owned interests in various producing oil and gas properties located in southeastern Ohio. We operate all of the wells involved with this partnership. This partnership has been liquidated and dissolved.

We have, pursuant to the terms of a restructuring plan set forth in a confidential disclosure memorandum dated March 3, 2000, amended the partnership agreements for the Energy Search Natural Gas 1997 L.P. and the Energy Search Natural Gas 1997-A L.P. to offer investor partners 9% redeemable convertible preferred stock at $4.00 per share, subject to adjustment, in exchange for their partnership interests. In connection with this transaction, we are offering up to 114,123 shares of our 9% redeemable convertible preferred stock. Currently, we have accepted subscriptions for 101,125 shares.

Financial Condition

Fiscal Year 1999

Total assets increased $8,864,518 or 35.4% from December 31, 1998 to December 31, 1999 primarily due to an increase of $475,828 in current assets, a net increase in oil and gas properties of $9,553,937 and after an offsetting decrease in other assets of $1,165,247.

Current assets for the year ended December 31, 1999 increased $475,828 to $2,142,684, or a 28.5% increase compared to current assets for the year ended December 31, 1998. The increase in current assets is due primarily to the existence of a restricted cash account of $834,217 and after an offsetting decrease in cash of $187,871 to $407,878 or 31.5% for the year ended December 31, 1999. Under the terms of the SPS Credit Facility, we were required to establish a restricted cash account, which is maintained by Southern Producer. All oil and gas revenue proceeds and amounts from any loans are deposited to this account. We may submit requests for reimbursement from the bank for certain operating expenses and principal and interest payments twice a month. Accounts receivable decreased $199,339 from the amount reported for the year ended December 31, 1998 to $781,542 for the year ended December 31, 1999 or 20.3%. The decrease is due primarily to an increase in the oil and gas revenue accrual and other receivables of approximately $423,000 and after an offsetting decrease of approximately $622,000 related to the agreement with Southern Producer which currently is purchasing approximately 60% of our natural gas revenue. This purchase has reduced the collection period from 45 to 60 days in prior years to approximately 30 days at December 31, 1999. Other current assets increased $28,821 from the amount reported for the year ended

Net oil and gas properties for the year ended December 31, 1999 increased $9,553,937 to $29,818,697 or 47.2% from the amount reported at December 31, 1998. The increase is primarily a result of continued successful drilling activity for our own account, and our purchase of oil and gas lease interests in proven properties. Oil and gas properties are depreciated and depleted by the units of production method using estimates of proven reserves. Accumulated depreciation, depletion and amortization at December 31, 1999 increased approximately $2,257,270 to $6,725,182 or 50.5% from the amount reported at December 31, 1998. The increase is due primarily to the increase in the capitalized cost of oil and gas properties and an increase in depletion rates. Proven properties, both tangible and intangible, are provided for on the units of production basis using estimates of proven reserves. The estimates of proven reserves are adjusted annually to the proven reserves as determined by our independent petroleum engineers, Wright & Company, Inc. See "--Results of Operations" for further discussion.

Proven properties for the year ended December 31, 1999 increased $8,114,041 to $21,279,899 or 61.6% from the amount reported at December 31, 1998. The increase is primarily due to our purchase of oil and gas lease interests in proven properties of approximately $2,562,262, our purchase of a 1% working interest in nine of our wells and the rights to purchase working interests in future wells for approximately $225,000 and the cost of drilling wells of $5,326,779.

In 1998 we began to implement a consolidation strategy which involved acquiring the oil and gas reserves held by certain affiliated drilling partnerships for cash or our stock based on an independent valuation. The strategy is beneficial because it allows us to consolidate the ownership of wells we operate and also should eliminate the administrative burden of managing and administrating affiliated drilling partnerships. We continued to implement this strategy through 1999 as discussed in the following paragraphs.

In a transaction completed in October of 1999, with an effective date of January 1, 1999, we purchased fractional working interests in 93 gross producing oil and natural gas wells located in southeastern Ohio from certain of our affiliated drilling partnerships and others. The affiliated drilling partnerships involved were the Natural Gas/Tax Credit 1993 L.P., the Natural Gas/Tax Credit 1993-A L.P., the Natural Gas/Tax Credit 1994 L.P, the Natural Gas/Tax Credit 1994-A L.P., the Natural Gas/Tax Credit 1995 L.P. and the Natural Gas/Tax Credit 1995-A L.P. All of the wells involved in this transaction were operated by and owned jointly with us. Since the purchase, the six affiliated drilling partnerships have been liquidated and dissolved. We paid an aggregate purchase price of $708,948, which included $504,815 in our common stock (229,955 shares) and $204,133 in cash.

Effective December 31, 1999, we issued an aggregate of 428,520 shares of 9% redeemable convertible preferred stock, $4.00 par value, to limited partners in the Energy Search Natural Gas Pipeline Income L.P. (the "Pipeline Income Partnership") in consideration for exchange of their partnership interests. The Pipeline Income Partnership owned a substantial interest in the natural gas pipeline and gathering system, which services certain natural gas wells operated by us in southeastern Ohio. Management determined that we had an impairment in our receivable, which resulted from loans for extensions to the pipeline, and our investment in the pipeline and recorded an impairment loss of approximately $640,000. In recording the preferred stock issued to acquire the pipeline, management concluded that the preferred stock should be discounted from its face amount by $1,290,840 and recorded at a net amount of $423,240.

Effective December 31, 1999, we closed the acquisition of working interests in a total of 13 gross natural gas and oil wells owned by the Natural Gas/Tax Credit 1996 L.P. and the Natural Gas/Tax Credit 1996-A L.P. We issued an aggregate of 165,450 shares of 9% redeemable convertible preferred stock to acquire the interests from these partnerships. Management determined that we had an impairment in our receivable and our investment in the partnerships and recorded an impairment loss of approximately $50,000. In recording the stock issued to acquire the partnership's working interests, management concluded that the preferred stock should be discounted from its face amount by $476,800 and recorded at a net amount of $185,000.

We increased capital expenditures for drilling and well related equipment from December 31, 1998 to December 31, 1999 in the amount of $3,671,501. The increase is primarily a result of increased drilling in 1999 and the purchase of oil and gas assets. We have drilled 38 net gas wells and one coalbed methane wells during 1999. Our SPS Credit

Other assets for the year ended December 31, 1999 decreased $1,165,247 to $1,926,546 or 37.7% from the amount reported at December 31, 1998. This decrease is due primarily to a decrease in investments in related partnerships of $1,710,247 to $3,020 or 99.8%, and after offsetting increases in the deferred tax assets of $222,300 and other assets of $323,411.

The investments in related partnerships decreased $1,710,247 from the amount reported for the year ended December 31, 1998 to $3,020 or 99.8% for the year ended December 31, 1999. This decrease is due primarily to impairment charges of $688,663 and the transfer of $979,179 of investments to proved properties due to the affiliated drilling partnership consolidations. Other assets increased $323,411 from the amount reported for the year ended December 31, 1998 to $528,191 or 157.9% for the year ended December 31, 1999 primarily due to the capitalization of net loan costs of $336,000 for the new SPS Credit Facility.

Total liabilities increased $10,859,809 or 122.3% from December 31, 1998 to December 31, 1999 due primarily to an increase in long-term debt of $8,596,655. In June 1999 we entered into the SPS Credit Facility which has an aggregate credit limit of $30,000,000. The SPS Credit Facility is secured by a pledge of all of our oil and gas assets. At December 31, 1999, we had borrowed approximately $18,019,344 against the SPS Credit Facility. See "--Cash Flows from Operations, Investing and Financing Activities" for further discussion.

Current liabilities increased $2,263,154 to $3,442,238 or 191.9% from December 31, 1998 to December 31, 1999. The increase primarily is due to an increase of $1,790,966 in the current portion of long-term debt to $2,337,373. The current portion of long-term debt increased approximately $2,268,600 due to the SPS Credit Facility, $6,700 for the SunTrust note payable, and decreased $484,400 due to the retirement of the Bank One debt. Accounts payable and accrued expenses increased $472,188 to $1,104,865 at December 31, 1999, an increase of 74.6%. See "--Liquidity and Capital Resources" for further discussion.

Long-term debt increased $8,596,655 from the amount reported at December 31, 1998 to $16,300,024 or 111.6% for the year ended December 31, 1999 primarily due to the SPS Credit Facility of approximately $15,750,700, notes payable to our officers of $180,000 and after offsetting decreases in the long-term debt portion due to the retirement of the Bank One debt of approximately $7,265,400 and a decrease in the long-term debt portion of the SunTrust note payable of approximately $68,600. Under their employment agreements, Messrs. Torrey, Cooper and Remine were entitled to certain rights and working interests in wells drilled and to be drilled by us. We purchased all existing working interests as well as all rights to participate in any future wells for a total of $225,000. We paid the purchase price to these officers by issuing three promissory notes of $75,000 each, which bear interest at 10% per annum. Any unpaid principal on these notes is due December 31, 2001.

Three Months Ended March 31, 2000

Total assets increased $3,018,111 or 8.9% from December 31, 1999 to March 31, 2000 primarily due to an increase of $225,007 in current assets, a net increase in oil and gas properties of $2,609,252 and an increase in other assets of $183,852.

Current assets for the three-month period ended March 31, 2000 increased $225,007 to $2,367,691, or a 10.5% increase compared to current assets for the year ended December 31, 1999. The increase in current assets is due primarily to the increase in cash (unrestricted and restricted) of $93,102 or 7.5%. Under the terms of the SPS Credit Facility, we were required to establish a restricted cash account, which is maintained by Southern Producer. All oil and gas revenue proceeds and amounts from any loans are deposited to this account. We may submit requests for reimbursement from Southern Producer for certain operating expenses and principal and interest payments twice a month. Accounts receivable increased $148,382 from the amount reported for the year ended December 31, 1999 to $929,924 for the three-month period ended March 31, 2000 or 19.0%. The increase is due primarily to a net increase in the oil and gas revenue accrual due to an increase in oil and gas production and an increase in the average oil and gas prices that we received. Other current assets decreased $16,477 from the amount reported for the

Net oil and gas properties for the three-month period ended March 31, 2000 increased $2,609,252 to $32,427,949 or 8.75% from the amount reported at December 31, 1999. The increase is primarily a result of continued successful drilling activity for our own account, and our purchase of oil and gas lease interests in proven properties. Oil and gas properties, both tangible and intangible, are depreciated and depleted by the units of production method using estimates of proven reserves. Accumulated depreciation, depletion and amortization at March 31, 2000 increased approximately $762,258 to $7,487,440 or 11.3% from the amount reported at December 31, 1999. The increase is due primarily to the increase in the capitalized cost of oil and gas properties and an increase in depletion rates.

In 1998, we began to implement a consolidation strategy which involved acquiring the oil and gas reserves held by certain affiliated drilling partnerships for cash or our stock based on an independent valuation. The strategy is beneficial because it allows us to consolidate the ownership of wells we operate and also should eliminate the administrative burden of managing, administrating, and in some cases, supporting the affiliated drilling partnerships. All of the 16 prior affiliated drilling partnerships have been or are in the process of being liquidated.

Proven properties for the three-month period ended March 31, 2000 increased $1,976,364 to $23,256,263 or 9.3% from the amount reported at December 31, 1999. The increase is primarily due to our purchase of producing properties from Cabot Oil & Gas Corporation of approximately $826,000, the cost of drilling wells of approximately $709,000 and the capitalization of certain company costs directly related to the drilling of our wells of approximately $379,000. These costs are related to the four wells drilled in the first quarter of 2000 and the costs of wells drilled in the fourth quarter of 1999 (five wells) and completed in the first quarter of 2000.

We increased capital expenditures for drilling and well-related equipment from December 31, 1999 to March 31, 2000 in the amount of $1,317,221. The increase is primarily due to our purchase of well equipment from Cabot Oil & Gas Corporation for approximately $874,000 and the cost of drilling and completing wells of approximately $443,000. We drilled four net gas wells in the first quarter of 2000.

Other assets for the three-month period ended March 31, 2000 increased $183,852 to $2,110,398 or 9.5% from the amount reported at December 31, 1999. This decrease is due primarily to a decrease in other property and equipment of approximately $17,000 to $270,118 or 5.9% due to current year depreciation, and an increase in other assets of approximately $202,000 due to the capitalization of net loan costs of approximately $214,000, the cost of financing the purchase of oil and gas properties from Cabot Oil & Gas Corporation as discussed above.

Total liabilities increased $3,441,435 or 17.4% from December 31, 1999 to March 31, 2000 due primarily to an increase in long-term debt of $3,722,013. In June 1999 we entered into the SPS Credit Facility which has an aggregate credit limit of $30,000,000. The SPS Credit Facility is secured by a pledge of all of our oil and gas assets. At March 31, 2000, we had borrowed approximately $21,846,358 against the credit facility. See "--Cash Flows from Operations, Investing and Financing Activities" for further discussion.

Current liabilities decreased $280,578 to $3,161,660 or 8.2% from December 31, 1999 to March 31, 2000. The decrease primarily is due to a decrease in accounts payable and accrued expenses of $263,758 to $841,107 at March 31, 2000, a decrease of 23.9%. See "--Liquidity and Capital Resources" for further discussion.

Long-term debt increased $3,722,013 from the amount reported at December 31, 1999 to $20,022,037 or 22.8% for the three-month period ended March 31, 2000 primarily due to the advances on the SPS Credit Facility of approximately $3,827,000, and after an offsetting decrease in notes payable to our officers of $105,000. Under their employment agreements, Messrs. Torrey, Cooper and Remine were entitled to certain rights and working interests in wells drilled and to be drilled by us. We purchased all existing working interests as well as all rights to participate in any future wells for a total of $225,000. We paid the purchase price to these officers by issuing three promissory notes of $75,000 each, which bear interest at 10% per annum. We paid each officer a principal payment of $35,000 in the first quarter of 2000. Any unpaid principal on these notes is due December 31, 2001.

Results of Operations

Fiscal Year 1999

For the year ended December 31, 1999 we had a net loss after tax of $3,227,976, compared to a net loss after tax of $394,428 for the year ended December 31, 1998.

For the year ended December 31, 1999, total net revenues increased $488,300 or 14.3% from $3,420,498 for the same period in 1998 to $3,908,798 due primarily to an increase in oil and gas revenue and after an offsetting decrease in turnkey revenue, management fees and other revenue.

Oil and gas revenue increased $793,895 to $3,391,770 for the year ended December 31, 1999, an increase of 30.6% over the amount reported for the year ended December 31, 1998 principally due to an increase in oil and natural gas production and an increase in the average oil and gas prices that we received. Average daily net oil production increased 193.1% from approximately 21.6 Bbls per day in 1998 to approximately 63.3 Bbls per day in 1999 primarily due to the purchase of producing properties from Mitchell Energy Corporation with an effective date of June 1, 1999. The average price realized per Bbl of oil during 1999 was $19.73, an increase of 68.1% versus the average price of $11.74 in 1998. Natural gas production increased 13.8% from 2.9 MMcf per day in 1998 to 3.3 MMcf per day in 1999 primarily due to the increase in the number of company wells drilled and the acquisitions of proven properties. Average natural gas prices realized increased approximately 3.3% from $2.41 per Mcf in 1998 to $2.49 per Mcf in 1999.

Given the SPS Credit Facility, the resulting aggressive drilling activity and the recent acquisitions, management anticipates continued growth in oil and gas revenues. The continued growth of our oil and gas revenues and reserves will depend on future drilling success, access to capital and the pricing of our primary commodity product, natural gas.

Management fees for the year ended December 31, 1999 decreased $74,486 to $71,100, a decrease of 51.2% over that reported as of December 31, 1998. This decrease is a result of our purchase of the working interests owned by certain affiliated drilling partnerships in 1998 and 1999. Currently, all of the 16 prior affiliated drilling partnerships have been or are in the process of being liquidated by us. Management fees are derived from services provided to affiliated drilling partnerships, and we expect management fees to continue to decrease.

For the year ended December 31, 1999, we did not recognize net turnkey revenue compared to the $67,312 recognized for the year ended December 31, 1998. Net turnkey revenue is drilling profit recognized upon the drilling to total depth of wells in affiliated drilling partnerships. We did not sponsor an affiliated drilling partnership in 1999 and do not intend to do so in 2000. In 1998, we drilled to total depth and recognized gross revenue of approximately $115,200, one gross well, for the 1998 affiliated drilling partnerships, and recognized turnkey expenses of approximately $47,900.

Other revenue decreased $163,797 for the year ended December 31, 1999, a decrease of 26.9% over the amount reported for the same period in 1998. This decrease is due primarily to a decrease in the gas transportation revenue earned by us. In 1998, we charged certain wells a transportation fee for gas flowing through our pipeline system. Effective in the third quarter of 1998, we eliminated the transportation fee. For the year ended December 31, 1999, we recognized no gas transportation revenue compared to gas transportation revenue of approximately $107,000 for the year ended December 31, 1998.

The decrease in other revenue also is due to a decrease in the gross operating commission revenue earned by Equity Financial for the year ended December 31, 1999 of approximately $6,500 to $457,202, a decrease of 1.4% over the amount reported for the same period in 1998. The decrease primarily is a result of Equity Financial having reduced its number of affiliates that generate commissions. For the year ended December 31, 1999, Equity Financial had a net loss of approximately $30,200. We cannot predict whether Equity Financial will be profitable in 2000. If it is not profitable at year end 2000, management will evaluate the continued viability of Equity Financial.

Interest income decreased approximately $20,900 during the year ended December 31, 1999 compared to the same period in 1998 due to the decrease in our interest-bearing cash balances.

Total operating expenses increased $3,328,241 to $7,293,286 or 83.9% for the year ended December 31, 1999 over the amount reported for the year ended December 31, 1998 primarily due to an increase in depreciation, depletion and amortization, impairment charges, general and administrative expenses and interest expense.

Production expenses increased $311,763 to $972,799 or 47.2% over the amount reported in 1998 primarily due to the larger number of wells that we now operate. On a Mcfe basis, production expenses increased 21.3% from $0.61 per Mcfe in 1998 to $0.74 per Mcfe in 1999. Depreciation, depletion and amortization expense increased $959,581 or 61.8% due primarily to our larger number of wells and increased production of net wells that we now own, which results in increased depletion rates for proved properties. Exploration expenses decreased $151,568 or 74.8% due to a decrease in dry hole costs and the completion of a project in 1998 implementing new technology for exploration and development of our reserves and well database.

Operating expenses for 1999 also include $688,663 in impairment charges reflecting the effect of the impairment recognized as a result of the affiliated partnership roll-up transactions completed in the fourth quarter of 1999. In recording these acquisitions, management concluded that the combined receivables from and investments in the partnerships were impaired. Management believes that the impairment charges are an isolated expense related to specific events in 1999. General and administrative expenses increased $853,287 to $2,010,177 or 73.8% for the year ended December 31, 1999 compared to the amounts reported for the year ended December 31, 1998. This increase primarily is a result of a decrease in the amount of general and administrative expenses capitalized to proved properties in 1999 and an increase in wages and salaries.

The increase in interest expense during 1999 reflects the increase in debt as a result of the Southern Producer credit facility.

Other income and expense changed from a net expense of $85,481 for the year ended December 31, 1998 to a net expense of $68,088 for the year ended December 31, 1999. The change primarily is a result of a decrease in the income of affiliated drilling partnerships of $71,141 and an offsetting decrease in affiliated drilling partnership reimbursements of $88,534. We expect this trend to continue because all of the 16 prior affiliated drilling partnerships have been or are in the process of being liquidated by us.

The income tax benefit decreased from a benefit of $235,600 for the year ended December 31, 1998 to a benefit of $224,600 for the year ended December 31, 1999. Management believes that the time horizon for the realization of the deferred tax asset has become less certain and will not report additional deferred tax asset until the certainty is clarified. The income tax benefit recognized in 1999 was reduced by the recognition of a valuation allowance for deferred tax assets of $1,100,600.

Three Months Ended March 31, 2000

For the three-month period ended March 31, 2000 we had a net loss after tax of $616,092, compared to a net loss after tax of $223,679 for the three-month period ended March 31, 1999.

Total net revenues increased $816,848 or 105.0% from $778,244 for the three-month period ended March 31, 1999 to $1,595,092 for the three-month period ended March 31, 2000 due primarily to an increase in oil and gas revenue and other revenue and after an offsetting decrease in management fees.

Oil and gas revenue increased $823,726 to $1,451,410 for the three-month period ended March 31, 2000, an increase of 131.2% over the amount reported for the three-month period ended March 31, 1999. The increase in revenue is principally due to our significant investments in and our development of proved properties which has resulted in an increase in oil and natural gas production and an increase in the average oil and gas prices that we received. Net paid production increased 74.2% from approximately 3.1 MMcfed for the three-month period ended March 31, 1999 to 5.4 MMcfed for the same period in 2000. Average natural gas prices realized increased approximately 30.9% from $2.23 per Mcfe for the three-month period ended March 31, 1999 to $2.92 per Mcfe for the same period in 2000.

Given the credit facility, the resulting aggressive drilling activity and the recent acquisitions, management anticipates continued growth in oil and gas revenues. The continued growth of our oil and gas revenues and reserves will depend on future drilling success, access to capital and the pricing of our primary commodity product, natural gas.

Management fees for the three-month period ended March 31, 2000 decreased $19,800 to $3,200, a decrease of 86.1% over that reported for the same period in 1999. This decrease is a result of our purchase in 1999 of the working interests owned by certain affiliated drilling partnerships. Currently, all of the 16 prior affiliated drilling partnerships have been or are in the process of being liquidated by us. Management fees are derived from services provided to affiliated drilling partnerships, and we expect management fees to continue to decrease.

We did not sponsor an affiliated drilling partnership in 1999 and do not intend to do so in 2000.

Other revenue increased $12,922 for the three-month period ended March 31, 2000, an increase of 10.1% over the amount reported for the same period in 1999. The increase in other revenue is due to an increase in the gross operating commission revenue earned by Equity Financial for the three-month period ended March 31, 2000 of approximately $7,418 to $128,313, an increase of 6.1% over the amount reported for the same period in 1999. For the three-month period ended March 31, 2000, Equity Financial had a net income of approximately $23,649 compared to a net loss of $9,749 for the three-month period ended March 31, 1999. The increase in net income is due to a decrease in operating expenses a result of Equity Financial having reduced its number of registered representatives and the related commission expense. We cannot predict whether Equity Financial will continue to be profitable in 2000. If it is not profitable at year end 2000, management will evaluate the continued viability of Equity Financial.

Interest income increased approximately $3,466 during the three-month period ended March 31, 2000 compared to the same period in 1999 due to the increase in our interest-bearing cash balances.

Total operating expenses increased $1,135,630 to $2,211,184 or 105.6% for the three-month period ended March 31, 2000 over the amount reported for the same period in 1999. The increase in operating expenses is primarily due to an increase in production costs, depreciation, depletion and amortization, general and administrative expenses and interest expense.

Production expenses increased $287,788 to $384,354 or 298.0% for the three-month period ended March 31, 2000 over the amount reported for the same period in 1999 primarily due to the larger number of wells that we now operate. We now operate approximately 290 more wells at March 31, 2000 than we operated at March 31, 1999 as a result of aggressive drilling activity and acquisitions.

Depreciation, depletion and amortization expense increased $413,363 or 106.5% for the three-month period ended March 31, 2000 over the amount reported for the same period in 1999 primarily due to our larger number of wells and increased production of net wells that we now own, which results in increased depletion rates for proved properties. Exploration expenses increased $9,245 or 59.1% over the amount reported at March 31, 1999.

General and administrative expenses increased $56,690 to $471,808 or 13.7% for the three-month period ended March 31, 2000 compared to the amount reported for the same period in 1999. This increase primarily is a result of an increase in professional fees, advertising fees, wages and salaries and after an offsetting decrease in the amount of general and administrative expenses capitalized to proved properties in the first three months of 2000.

The increase in interest expense during the first three months of 2000 reflects the increase in debt as a result of the Southern Producer credit facility.

There was no other income and expense recognized in the first quarter of 2000 compared to a net expense of $22,369 for the three-month period ended March 31, 1999. The change primarily is a result of a decrease in the income of affiliated drilling partnerships of $5,347 and an offsetting decrease in affiliated drilling partnership reimbursements of $27,716. We expect this trend to continue because all of the 16 prior affiliated drilling partnerships have been or are in the process of being liquidated by us.

There was no income tax benefit or expense recognized in the first quarter of 2000 compared to an income tax benefit of $96,000 for the three-month period ended March 31, 1999. Management believes that the time horizon for the realization of the deferred tax asset has become less certain and will not report additional deferred tax asset until the certainty is clarified. The income tax benefit recognized in 1999 was reduced by the recognition of a valuation allowance for deferred tax assets of $1,100,600.

Cash Flow from Operations, Investing and Financing Activities

Fiscal Year 1999

We provided $488,217 of net cash flow from operating activities for the year ended December 31, 1999 and $244,823 of net cash flow from operating activities for the same period in 1998. Cash was absorbed by a loss of $3,227,976 for the year ended December 31, 1999 and a loss of $394,428 for the year ended December 31, 1998. These amounts are adjusted for certain non-cash items including depreciation, depletion and amortization of $2,511,266 for the year ended December 31, 1999 and $1,551,685 for the year ended December 31, 1998, which have been added to net income in arriving at net cash used by operating activities. The amounts also are adjusted for an increase in the deferred tax asset of $222,300 for the year ended December 31, 1999 and $235,600 for the year ended December 31, 1998, which has reduced net income in arriving at net cash used by operating activities. Other non-cash items which have been added to net income in arriving at net cash flow from operating activities for the year ended December 31, 1999 are impairment charges of $688,663 and stock compensation expense of $190,939. Cash was provided by a decrease in accounts receivable of $136,187 for the year ended December 31, 1999 and $139,876 for the year ended December 31, 1998, due to a decrease in the oil and gas revenue receivable. Cash was used by an increase in other current assets of $28,821 and provided by a decrease in other assets of $4,286 and an increase in accounts payable and accrued expenses of $472,188 for the year ended December 31, 1999. Cash was provided by a decrease in other current assets of $1,444 and used by an increase in other assets of $29,760 and a decrease in accounts payable and accrued expenses of $724,071 for the year ended December 31, 1998.

Cash flows used for investing activities decreased from $10,099,654 for the year ended December 31, 1998 to $9,478,062 for the year ended December 31, 1999. The primary investment activities for the year ended December 31, 1999 were purchases of proven properties of $5,738,412, purchases of wells and related equipment of $3,679,425, purchases of other property and equipment of $80,162 and purchases of other oil and gas leases of $25,665. The primary investment activities for the year ended December 31, 1998 were purchases of proven properties of $6,839,114, purchases of wells and related equipment of $3,256,434, purchases of other property and equipment of $30,951, contributions to affiliated drilling partnerships of $34,510 and purchases of other oil and gas leases of $15,651. The cash flow from investing activities were distributions from affiliated drilling partnerships of $45,602 for the year ended December 31, 1999 and $77,006 for the year ended December 31, 1998.

Cash flows from financing activities increased $1,437,927 from the amount reported at December 31, 1998 to $9,636,191 for the year ended December 31, 1999. The significant sources of financing activities in 1999 were proceeds of $1,020,000 from the Bank One credit facility, before payoff with the proceeds of the SPS Credit Facility in June of 1999, and the funding of the Southern Producer credit facility in the amount of $18,019,344. The Southern Producer funds were used to retire our existing debt with Bank One in the amount of $8,769,776, to pay accrued interest expense and other expenses to Bank One in the amount of approximately $54,967, to fund the purchase of producing properties from Mitchell Energy Corporation and to fund operations and developmental drilling on oil and gas properties in Ohio and West Virginia in the amount of approximately $9,194,601. See "--Liquidity and Capital Resources" for further discussion. The other significant uses of cash flows from financing activities were the payments on long-term debt of $61,947 for the year ended December 31, 1999 and $166,780 for the year ended December 31, 1998, retirement of Bank One debt of $8,769,776 discussed above and payments on notes payable of $45,000 to each of Messrs. Torrey, Cooper and Remine. The notes payable to these officers were for their 1% working interests or rights to working interests in company wells. Other uses of cash flows from financing activities were the payment of loan issue costs of $422,899 for the year ended December 31, 1999 and the payment of dividends on preferred stock of $86,895 for the year ended December 31, 1999 and $17,601 for the year ended December 31, 1998.

The primary source of financing activities for the year ended December 31, 1998 was from the expansion of long-term debt in the amount of $7,599,093 and the net proceeds from the sale of preferred stock in the amount of

Three Months Ended March 31, 2000

We used $291,657 of net cash flow from operating activities for the three-month period ended March 31, 2000 and provided $58,807 of net cash flow from operating activities for the same period in 1999. Cash was absorbed by a loss of $616,092 for the three-month period ended March 31, 2000 and a loss of $223,679 for the three-month period ended March 31, 1999. These amounts are adjusted for certain non-cash items including depreciation, depletion and amortization of $801,402 for the three-month period ended March 31, 2000 and $388,039 for the same period in 1999, which have been added to net income in arriving at net cash used by operating activities. The amounts also are adjusted for an increase in the deferred tax asset of $96,000 for the three-month period ended March 31, 1999, which has increased the net loss in arriving at net cash provided by operating activities. Cash was used by an increase in accounts receivable of $148,382 for the three-month period ended March 31, 2000 due to an increase in the oil and gas revenue receivable. Cash was provided by a decrease in other current assets of $16,477 and used by an increase in other assets of $4,072 and a decrease in accounts payable and accrued expenses of $340,990 for the three-month period ended March 31, 2000. Cash was provided by a decrease in accounts receivable of $58,299 and used by an increase in other current assets of $13,534 and other assets of $30,605, and a decrease in accounts payable and accrued expenses of $18,366 for the three-month period ended March 31, 1999.

Cash flows used for investing activities increased from $643,073 for the three-month period ended March 31, 1999 to $3,316,833 for the three-month period ended March 31, 2000. The primary investment activities for the three-month period ended March 31, 2000 were purchases of proven properties of $1,916,364, purchases of wells and related equipment of $1,317,221, purchases of other property and equipment of $5,438 and purchases of other oil and gas leases of $77,925. The primary investment activities for the three-month period ended March 31, 1999 were purchases of proven properties of $537,128, purchases of wells and related equipment of $114,772 and purchases of other property and equipment of $5,708. The cash flow from investing activities were distributions from affiliated drilling partnerships of $16,014 for the three-month period ended March 31, 1999 and $115 for the three-month period ended March 31, 2000.

Cash flows from financing activities increased $3,462,412 from the amount reported at March 31, 1999 to $3,701,592 for the year ended March 31, 2000. The significant sources of financing activities in 1999 were proceeds of $270,000 from the Bank One credit facility, before payoff with the proceeds of the SPS Credit Facility in June of 1999. The significant source of financing activities in 2000 were the funding of the Southern Producer credit facility in the amount of $3,827,014. The Southern Producer funds were used to fund the purchase of producing properties from Cabot Oil & Gas Corporation and to fund operations and developmental drilling on oil and gas properties in Ohio and West Virginia. See "Liquidity and Capital Resources" for further discussion. The other significant uses of cash flows from financing activities were the payments on long-term debt of $16,821 for the three-month period ended March 31, 2000 and $14,184 for the three-month period ended March 31, 1999 and payments on notes payable of $35,000 to each of Messrs. Torrey, Cooper and Remine. The notes payable to these officers were for their 1% working interests or rights to working interests in company wells. Other uses of cash flows from financing activities were the payment of loan issue costs of $3,601. Other uses of cash flows from financing activities were the payment of stock issuance costs of $16,636 for the three-month period ended March 31, 1999.

Liquidity and Capital Resources

Our primary source of funds has been from borrowing against the SPS Credit Facility. The proceeds from these sources have been used to fund our operations, acquisitions and developmental drilling activities in the southeastern Ohio and Southern West Virginia areas.

We intend to fund budgeted capital expenditures in 2000 primarily from cash flow from operations and borrowings. We have in place with the SPS Credit Facility with a credit limit of $30,000,000 and upon which $21,846,358 was drawn down as of March 31, 2000. The SPS Credit Facility is collateralized by a first lien on all of our oil and natural gas properties. Interest is payable at 11% per annum and Southern Producer receives a 3% overriding

We also have a note payable to SunTrust Bank with an outstanding principal balance of $421,232 as of March 31, 2000. The note is collateralized by non oil and gas equipment, payable in monthly installments of principal and interest at 7.75% per annum, with unpaid principal balance due December 5, 2003. We are subject to various loan covenants in connection with our credit facilities including requirements on tangible net worth, working capital, debt to tangible net worth, limits on partnership subsidies, restrictions on payment of dividends and general and administrative expenses.

We do not anticipate that we will realize any funds by the sponsoring of an affiliated drilling partnership in 2000.

We have experienced and expect to continue to experience substantial working capital requirements due primarily to our active exploration and development programs.

We believe that cash flow from operations and borrowings under existing or contemplated additional credit facilities should allow us to implement our present business strategy in 2000. If sufficient capital resources are not available to us, our drilling of new wells and property development activities would be substantially reduced.

Effects of Commodity Pricing and Inflation

Our revenues, profitability, future growth and ability to borrow funds or obtain additional capital, and the carrying value of our properties, substantially depend on prevailing prices of natural gas and oil. We cannot predict future natural gas and oil price movements. Declines in prices received for natural gas and oil may harm our financial condition, liquidity, ability to finance capital expenditures and results of operations. Lower prices also may impact the amount of reserves we can economically produce. If the price of natural gas and oil increases (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Recent rates of inflation have had a minimal effect on us.

Environmental and Other Regulatory Matters

Our business is subject to federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, natural gas and oil, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years. Although we believe we substantially comply with all applicable laws and regulations, the requirements imposed by laws and regulations may change. We cannot predict the ultimate cost of compliance with these requirements. Our business, financial condition and results of operations would be harmed if we do not meet environmental requirements. Compliance with applicable governmental laws and regulations has not materially harmed our earnings or competitive position to date. Future regulations may add to the cost of, or limit, drilling activity.

Description of Business

General

Energy Search, Incorporated was organized as a Tennessee corporation in 1990. We are an independent oil and natural gas company engaged in the exploration, development, production and acquisition of domestic oil and natural gas properties primarily in the Appalachian Basin. In 1999, 90% of our production was natural gas. Beginning in January 1997, we shifted our focus from drilling primarily for Tennessee limited partnerships which we sponsored ("affiliated drilling partnerships") to developing reserves for our own account. As a result of this shift, our daily net paid production averaged approximately 3.6 million cubic feet equivalent per day ("MMcfed") in 1999, and currently exceeds 6.0 MMcfed. We drilled 38 net wells and one coalbed methane well in 1999, and four net wells in the first quarter of 2000.

According to the 1999 year-end reserve report prepared by Wright & Company, Inc., our independent certified petroleum engineers, as of December 31, 1999 we had proven natural gas reserves of 63.6 billion cubic feet of gas equivalent ("Bcfe") with a pre-tax present value of proved natural gas and oil reserves discounted at the rate of 10% per year ("SEC PV-10") of approximately $59,700,000. Proven reserves have increased 45.2% for 1999 compared to the amount reported for 1998 as a direct result of successful drilling and acquisitions. SEC PV-10 proven reserve value has increased 93.8% for 1999 compared to 1998 due to our proven reserve growth and an increase in the price of the natural gas and oil commodities. We expect our future growth to be driven by development, exploitation and controlled exploration drilling on our existing properties and the continuation of an opportunistic acquisition strategy in the Appalachian Basin region. We drill primarily developmental wells and, on occasion, step out or exploratory wells to develop new areas.

We presently focus our operations entirely in the Appalachian Basin. The Appalachian Basin is characterized by shallow natural gas formations, which historically have provided for highly predictable drilling success rates. We currently enjoy economic completion of over 90% of all wells drilled. In addition, because wells drilled in the Appalachian Basin are closer to the large demand centers in the northeastern United States, natural gas from this area typically commands a premium price relative to natural gas produced in areas such as the Gulf Coast and Mid-Continent regions of the United States. In 1999, we had an approximate .35¢ per Mcf positive premium to the NYMX Henry Hub quote.

Throughout the 1990s, we drilled an average of approximately 25 to 35 wells per year. Until February of 1997, substantially all of our wells were drilled in joint ventures with affiliated drilling partnerships which raised over $40,000,000 in investor capital and were syndicated primarily by our subsidiary, Equity Financial Corporation, a member of the National Association of Securities Dealers, Inc. The affiliated drilling partnerships participated primarily in development drilling in Washington, Athens and Meigs Counties, Ohio. We have drilled over 200 wells with affiliated drilling partnerships. We did not sponsor an affiliated drilling partnership in 1999 and do not expect to sponsor any in 2000 or the foreseeable future.

In 1998 we began to implement a consolidation strategy which involved acquiring the oil and gas reserves held by our affiliated drilling partnerships for cash or our common and preferred stock. In April 2000, we acquired the assets of the final two partnerships. Therefore, we have consolidated the ownership of wells we operate and eliminated the administrative burden of managing and administrating these partnerships.

During the last 24 months, we have grown primarily through developmental drilling and opportunistic acquisitions of Appalachian properties for our own account and the subsequent development, exploitation and exploration of these properties. The drilling and acquisition activities have substantially increased our reserves and production. In June of 1999, we entered into a $30,000,000 credit facility with Southern Producer Services, Ltd., of Houston, Texas. This facility replaced our previous bank credit facility and is available to fund future drilling and acquisitions.

Management's business plan currently anticipates drilling approximately 75 wells in 2000 using net cash flow, additional debt from the Southern Producer credit facility and, perhaps, proceeds of future equity offerings. Management believes it can efficiently maintain the planned level of drilling activity in the foreseeable future. Management plans to continue drilling and development activities primarily for our own account which should enable us to expand activities and operations. Management believes this plan should result in the continued growth of our proved natural gas and oil reserves, net cash flow and shareholder value. If our revenues and net cash flows grow, we intend to expand drilling activities and continue to evaluate and execute natural gas and oil property acquisitions.

Recent Acquisitions

Effective January 1, 1999, we acquired fractional working interests in various producing oil and natural gas wells located in southeastern Ohio from certain affiliated drilling partnerships and other fractional working interest owners. The affiliated drilling partnerships involved were known as the Natural Gas/Tax Credit 1993 L.P., the Natural Gas/Tax Credit 1993-A L.P., the Natural Gas/Tax Credit 1994 L.P., the Natural Gas/Tax Credit 1994-A L.P., the Natural Gas/Tax Credit 1995 L.P. and the Natural Gas/Tax Credit 1995-A L.P. All of the wells involved in this transaction were operated by and owned jointly with us. Since the acquisition, the six affiliated drilling

Effective June 1, 1999, we closed the purchase of producing properties, totaling 99 wells, and certain undeveloped acreage located in Gallia, Lawrence and Vinton Counties, Ohio, from Mitchell Energy Corporation utilizing proceeds from our Southern Producer credit facility.

In October 1999, we, as managing general partner of Energy Search Natural Gas Pipeline Income L.P., amended the limited partnership agreement for that partnership. The amendment expanded the limited liquidity feature to allow us, at our discretion, to offer securities to limited partners in the partnership in exchange for their limited partnership interest. Under this new provision of the partnership agreement, we offered exclusively to limited partners in the partnership up to 428,520 shares of 9% redeemable convertible preferred stock at an exchange value of $4.00 per share. The offering was substantially completed by December 31, 1999, and we ultimately issued 428,520 shares of the preferred stock to the limited partners.

Effective December 31, 1999, we closed the acquisition of working interests in a total of 13 gross natural gas and oil wells owned by the Natural Gas/Tax Credit 1996 L.P. and the Natural Gas/Tax Credit 1996-A L.P. We issued an aggregate of 165,450 shares of 9% redeemable convertible preferred stock to acquire the interests from these partnerships.

In January 2000, we retained the investment banking firm of McDonald Investments Inc., to explore strategic alternatives to maximize shareholder value.

In a transaction completed in February 2000, we issued 15,000 shares of our 9% redeemable convertible preferred stock to limited partners in the Energy Search Natural Gas 1998 L.P., which owned interests in various producing oil and gas properties located in southeastern Ohio. We operate all of the wells involved with this partnership. This partnership has been liquidated and dissolved.

In March of 2000, we closed the purchase of approximately 6,500 acres of oil and gas properties from Cabot Oil & Gas Corporation. The property is contiguous to our existing field in Raleigh County, West Virginia and includes 45 producing wells and related gas gathering equipment. We estimate this acquisition will increase production approximately 500 Mcfe per day. We funded the purchase of these properties with proceeds from our Southern Producer credit facility. The effective date of this purchase was January 1, 2000. In connection with this financing, we issued 105,000 shares of common stock to Southern Producer.

We have, pursuant to the terms of a restructuring plan set forth in a confidential disclosure memorandum dated March 3, 2000, amended the partnership agreements for the Energy Search Natural Gas 1997 L.P. and the Energy Search Natural Gas 1997-A L.P. to offer investor partners 9% redeemable convertible preferred stock at $4.00 per share, subject to adjustment, in exchange for their partnership interests. In connection with this transaction, we are offering up to 114,123 shares of our 9% redeemable convertible preferred stock. Currently, we have accepted subscriptions for 101,125 shares.

Business Strategy

Our objective is to maximize shareholder value by growing reserves, production, cash flow and earnings through active development of existing properties and through the opportunistic acquisition of Appalachian properties with underexploited value. Fundamental to this objective is our focus on the Appalachian Basin region and our foundation of experienced technical personnel strengthened by a high level of financial and transactional experience.

Geographic and Natural Gas Focus. We focus on natural gas in the Appalachian Basin. Unlike many exploration and production companies, we concentrate on one region and are one of only a few publicly traded pure Appalachian Basin natural gas producers. We believe this region remains attractive for future development, exploration and acquisition activities due to:

This geographic focus has enabled us to build and utilize a base of region-specific geological, geophysical, engineering and production expertise.

Management believes that natural gas is gaining popularity as a power source and should continue to increase market share relative to other fossil fuels due to its efficiency and environmental characteristics. Uses of natural gas include:

Management believes that natural gas in the Appalachian Basin enjoys favorable economics. The Appalachian Basin has a price advantage over the Gulf Coast and other natural gas producing regions given its proximity to the primary markets on the east coast.

Acquisition of Properties with Underexploited Value. Our acquisition strategy is to purchase Appalachian Basin natural gas properties from large independent companies and major oil companies. These properties provide opportunities to increase reserves, production and cash flow through development and exploitation drilling and lease operating expense reduction. We use in-house landmen and a network of relationships in the region to discover acquisitions that are not widely advertised. We believe that our standing and reputation in the region have prompted other companies to approach us for potential acquisitions.

Focus on Development and Exploitation with Controlled Exploration. We integrate our reservoir and production engineering expertise with our geological interpretation abilities to enhance our exploration and production business. Our ability to integrate geophysics with detailed geology, reservoir engineering and production engineering allows us to identify multiple development and exploratory prospects in mature producing fields that previous operators did not identify and to identify unexploited multiple horizon wells. We have assembled a multi-year inventory of development, exploitation and exploratory drilling opportunities in the Appalachian Basin. Most of the properties comprising this inventory are located in fields that have established production histories. Based on our experience on these properties and on independent reports from our petroleum engineers, we believe these properties could yield significant additional recoverable reserves.

Control of Operations. We operate and maintain a majority working interest position in each of our core properties. Consequently, we can control directly all aspects of drilling, completion and production. In addition, we seek to maintain a low cost overhead structure by controlling the timing of the development of our properties. By operating producing wells, we believe that we are well positioned to control the expenses and timing of development and exploitation of these properties and better manage cost reduction efforts.

Integration. In addition to maintaining operational control of drilling activities, we operate and significantly control the majority of the gas gathering and pipeline systems in our fields through which our production is delivered to market. We believe that this integration has allowed us not only to improve overall margins on the sale of natural gas, but also avoid shut-ins, pressure problems and/or allocation problems sometimes experienced by using third party gathering systems. We actively examine additional integration possibilities for transmission, gathering and marketing of natural gas to continue this integration of our natural gas business.

Employment of Technology. We use advanced technology in development and exploration activities to reduce drilling risks and finding costs and to prioritize our drilling prospects based on return potential. Specifically, we use GeoGraphix for determining well location, mapping and possible viability of potential leases. GeoGraphix is a leading program used for mapping reserve geology and overall reserve evaluation. We also have a proprietary database of over 25,000 wells that we have integrated into GeoGraphix which has made the program a powerful planning tool. We have spent years developing this extensive proprietary database and have a full-time employee dedicated to accumulating and inputting data from our drilling experiences and from public and other records.

Offices and Employees

Our administrative offices are located at Suite 200, 280 Fort Sanders West Boulevard, Knoxville, Tennessee 37922. At this office, all executive management, financial, accounting and general administrative functions for us and our affiliated drilling partnerships are performed. Our main operations office is located at 217 Second Street, Marietta, Ohio. All geological, engineering and exploration and production activities are performed from the Marietta office.

Currently, we have 22 full-time and four part-time employees. As drilling production activities increase, we intend to hire additional technical, operational and administrative personnel as appropriate. None of our employees are represented by a labor union. We believe that our relations with employees are positive. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the area of drilling services, water hauling, acquisition of leases and lease options, construction, design, well-site surveillance, permitting and environmental assessment. We believe that this use of third-party service providers enhances our ability to contain general and administrative expenses.

Description of Property

Company Oil and Natural Gas Assets

As of December 31, 1999, we partially owned and operated approximately 632 gross wells (564 gross productive wells), 623 net (553 net productive wells) to us, and owned and operated approximately 229 miles of natural gas gathering systems. We have 190,119 gross acres, 183,691 net to us, of oil and natural gas leases in Ohio and West Virginia in the heart of the Appalachian Basin. For the year ended December 31, 1999, we had net average daily paid production of approximately 3.6 MMcfed. As of March 31, 2000, our net paid production of natural gas exceeded 6.0 MMcfed.

We have under lease approximately 17,000 lease acres (the "Beaver Lease") in Raleigh County, West Virginia. We plan to continue drilling the Beaver Lease for our own account and to exploit other similar opportunities in the area. We also have production on approximately 1,700 additional acres in Wood, Gilmer and Ritchie Counties, West Virginia.

In 1998 we acquired approximately 32,000 lease acres on which to develop coalbed methane gas in Raleigh County, West Virginia. We began recompletion operations in May 1999 and have drilled and/or recompleted a total of three coalbed methane wells in 1999 .

We have under lease approximately 60,000 acres of mostly contiguous property located in Fayette and Raleigh Counties, West Virginia. We began drilling this acreage in March 1999.

As a result of the Mitchell Energy Corporation acquisition, we acquired 99 wells and 18,072 developed gross acres, 17,714 developed net acres and 21,336 gross/net undeveloped acres, located in Gallia, Lawrence and Vinton Counties, Ohio. These properties consist of two producing fields, the Arabia Gas field and the Greasy Ridge Oil field. We began drilling in December 1999.

In March of 2000, we purchased approximately 6,500 acres of oil and gas properties from Cabot Oil & Gas Corporation. The property is contiguous to our existing field in Raleigh County, West Virginia and includes 45 producing wells and related gas gathering equipment.

We have acquired and currently own rights associated with a variety of leases in southeastern Ohio. The leases consist of "fields," for example the Simmons field, which is approximately 9,000 acres of oil and natural gas properties and the Bartlett and Torch fields, which are accumulations of many small lease tracts from individual owners into relatively contiguous field operation areas. Additionally, during 1999 we acquired, by way of a farm-in agreement, the operating rights relating to approximately 3,694 acres and a conventional oil and gas lease agreement embodying 2,903 acres. This acreage is located in proximity to the Simmons field. These areas are located in Athens, Meigs, Morgan and Washington Counties, Ohio.

Gas Gathering Systems. Throughout our various fields of operation in Ohio and West Virginia, we own and operate approximately 229 miles of pipeline and natural gas gathering systems. Substantially all of the wells that we drill and complete are connected to these natural gas gathering systems. The gas gathering systems collect the natural gas from the wells, with the majority sent through one or more compressor stations to enhance transportability and deliver it to interstate pipeline carriers.

Oil and Natural Gas Reserves

Our oil and natural gas reserves are located in Ohio and West Virginia. Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data indicate are reasonably certain to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells using existing equipment and operating methods. Proved undeveloped reserves are proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells at depths below the present bottom of the wells.

The following table summarizes information with respect to the estimated net proved oil and natural gas reserves as reviewed, evaluated and certified by Wright & Company, Inc., independent certified petroleum engineers, attributable to our interests in oil and natural gas properties as of December 31, 1999, 1998 and 1997.

The reserve amounts in the following tables represent well interests and reserves directly owned 100% by us. While we may own a separate percentage of the entire working interest in certain wells with an affiliated drilling partnership, the partnership's respective percentage ownership is separate and direct. No reserves included as owned by us are owned indirectly through any affiliated drilling partnership.

TOTAL ESTIMATED NET RESERVE QUANTITIES

We have not filed our estimated proved reserves with or included the information in reports to any federal agency.

Discounted Present Value of Future Net Revenues

The following table represents the estimated future net revenues and the present value of the future estimated net reserves discounted at a rate of 10% per year from our proved developed producing, proved developed non-producing and proved undeveloped reserves.

With respect to the table below, the estimated discounted present value of future net cash flows from proved oil and gas reserves is computed assuming a constant net price of $23.25 per barrel of oil and $3.25 per Mcf of natural gas for all fields except the Mitchell field acquired from Mitchell Energy, which is computed using a gas price of $3.00. For the fiscal year ended December 31, 1999, we received gross oil prices ranging from $9.38 to $23.50 per barrel and gross natural gas prices ranging from $1.65 to $3.47 per Mcf before royalties and gathering and transportation costs.

ESTIMATED DISCOUNTED PRESENT VALUE OF FUTURE NET
CASH FLOWS FROM PROVED OIL AND NATURAL AS RESERVES

In accordance with applicable requirements of the Securities and Exchange Commission, estimates of our proved reserves and future cash flows are made using sales prices estimated to be in effect as of the date of the reserve estimates and are held constant throughout the life of the properties, except to the extent a contract specifically provides otherwise. Estimated quantities of proved reserves and future cash flows therefrom are affected by natural gas and oil prices, which have fluctuated widely in recent years.

There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values, including many factors beyond the control of the producer. The reserve data set forth in this amended Prospectus represents estimates only. The significance of the estimates are highly dependent upon the accuracy of the assumptions upon which they were based. Reserve engineering and evaluation is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers and geologists often vary. In addition, estimates of reserves are subject to revision by the results of drilling, testing and production after the date of the estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. While we believe that reserve estimates in this amended Prospectus are reasonable, you should know that subsequent reservoir performance, the timing and success of future development drilling and changes in pricing structure or market demand will affect the reserve estimates.

In general, the volume of production from oil and gas properties declines as reserves are depleted. Unless we purchase properties containing proven reserves or conduct successful exploration and development activities, or both, our proven reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent upon our level of success in purchasing or developing additional reserves.

Producing Wells

The following table contains information regarding our ownership of productive wells in Ohio and West Virginia as of December 31, 1999. For purposes of this table, productive wells are producing wells and wells capable of production. A gross well is a well in which we own a working interest. The number of gross wells is the total number of wells in which we own a working interest. A net well is considered to exist when the sum of the fractional ownership interests in gross wells equals one. The number of net wells is the sum of the fractional working interests which we own in gross wells expressed as whole numbers and fractions thereof.

The well amounts in the table below represent well interests directly owned 100% by us. While we may own a separate percentage of the entire working interest in certain wells with an affiliated drilling partnership, the partnership's respective percentage ownership is separate and direct. No well interests included as owned by us are owned indirectly through any affiliated drilling partnership.

PRODUCTIVE WELL SUMMARY

The following table lists certain information regarding the production volumes of, average sales prices received for, and average production costs associated with, our sales of oil and natural gas for the periods indicated.

The production volumes in the table above reflect net production volumes from our well interests after reduction for gas pipeline shrinkage and compressor use (approximately 7% of total gross production) and after reduction for landowner and overriding royalties (approximately 15% of production delivered for sale). The oil and gas sales amount in the Consolidated Statement of Operations included elsewhere in this amended Prospectus for the years presented represents the sale of oil and gas production actually delivered, after reduction for line shrinkage and compressor use, and sold for our account, excluding revenues payable to landowner and overriding royalty interests.

Development, Exploration and Acquisition Expenditures

The following table lists information regarding the costs we incurred in the development, exploration and acquisition activities on our Ohio and West Virginia properties during the periods indicated:

We have drilled or participated in the drilling of wells in our Ohio and West Virginia properties as listed in the table below for the periods indicated.

In the first quarter of 2000, we have drilled three wells and are in the process of drilling one well in southeastern Ohio, and are preparing several locations for drilling in Ohio and West Virginia.

Oil, Natural Gas and Coalbed Methane Leases

Leasehold Acreage. As of December 31, 1999, we owned or controlled oil and natural gas leasehold acres located in Ashtabula, Athens, Gallia, Lawrence, Meigs, Morgan, Tuscarawas, Washington and Vinton Counties, Ohio, and in Fayette, Gilmer, Ritchie, Wood and Raleigh Counties, West Virginia, and coalbed methane leasehold acreage in Raleigh County, West Virginia.

The following table lists information regarding our developed and undeveloped leasehold acreage as of December 31, 1999:

LEASEHOLD ACREAGE

Substantially all of our Ohio and West Virginia leases are subject to landowner royalties of 12.5% and, occasionally, subject to additional overriding royalty interests ranging from 1.8% to 10.5%. Thus, our net revenue interest in the Ohio and West Virginia leases generally ranges from 84.5% to 80.0%.

Legal Proceedings

          We are not the subject of any litigation. Nor do we have knowledge of any facts that we believe would result in litigation against us.

Management

The Company's Board of Directors currently consists of five directors, two of whom are standing for reelection. The Company's Charter and Bylaws provide that the Board of Directors shall be divided into three classes, with each class to be as nearly equal in number as possible. Each class of directors serves a term of office of three years, with the term of one class expiring at the annual meeting of shareholders in each successive year. The following table lists information regarding each director as well as our Vice President of Exploration and Development.

Nominees for Election to Terms Expiring in 2003

Robert L. Remine (age 51), a certified public accountant, has been a director of the Company since its inception in 1990. Mr. Remine, a founder of the Company, has served as the Company's Secretary and Treasurer since 1990. Mr. Remine actively has participated in the syndication, capital formation, investment and management of over $50 million in oil and gas related programs for the Company. Mr. Remine is responsible for overview of all financial, tax and accounting matters of the Company. Mr. Remine is a registered securities representative, principal, director and secretary and treasurer of Equity Financial Corporation ("EFC"), a wholly owned subsidiary of the Company. EFC is a member of the National Association of Securities-Dealers and a registered broker-dealer with the Securities and Exchange Commission and in the states of Tennessee, Alabama, Georgia, Florida and Kentucky.

Kim A. Walbe (age 54) has been a director of the Company since March 1997. Mr. Walbe is an independent consultant supervising drilling and completion of wells in West Virginia, Virginia and Kentucky. Mr. Walbe prepares oil and gas reserve reports for wells in New York, Pennsylvania, West Virginia, Ohio, Kentucky and Virginia. Mr. Walbe also is involved in supervising acquisition quality control and interpretation of all forms of electric log data, including deviated well data. Mr. Walbe functions as well-site geologist in Kentucky, West Virginia and Virginia; evaluates leases in Ohio, Virginia, Pennsylvania, West Virginia, New York and Kentucky; interprets aerial photography and prepares geological structure maps from interpretations; prepares lineation/fracture/borehole television maps for Devonian Shale well site selection and prepares and delivers testimony in oil and gas litigation as an expert witness. Mr. Walbe is an Adjunct Professor of Geology at the University of Charleston. Mr. Walbe also has been a contract consultant since 1985 to the Gas Research Institute's Devonian Shale Program. Mr. Walbe is a member of the Appalachian Geological Society, American Institute of Professional Geologists, Society of Petroleum Engineers of A.I.M.E., Society of Professional Well Log Analysts and American Society for Photogrammetry and Remote Sensing.

Incumbent Director - Term Expiring in 2001

Charles P. Torrey, Jr. (age 53) has been a director of the Company since its inception in 1990. Mr. Torrey, a founder of the Company, has served as the Company's Chief Executive Officer since 1990. Mr. Torrey actively has participated in the syndication, capital formation, investment and management of over $50 million in oil and gas

Incumbent Directors - Terms Expiring in 2002

Richard S. Cooper (age 50) has been a director of the Company since its inception in 1990. Mr. Cooper, a founder of the Company, has served as the Company's President responsible for all day to day operations since 1990. Mr. Cooper actively has participated in the syndication, capital formation, investment and management of over $50 million in oil and gas related programs for the Company. Mr. Cooper is licensed to practice law in the State of Tennessee and, before 1991, practiced business and real estate law in Knoxville, Tennessee.

Douglas A. Yoakley (age 45), a certified public accountant, has been a director of the Company since March 1997. Mr. Yoakley founded Pershing & Yoakley & Associates, a multi-specialty public accounting firm with over 100 employees in three offices, including Knoxville and Chattanooga, Tennessee and Clearwater, Florida. Mr. Yoakley is a member of the American Institute of Certified Public Accountants and the Tennessee Society of Certified Public Accountants. Mr. Yoakley serves as a director for The Philadelphians, Inc., Healthcare Horizons, Inc., Camel Manufacturing, Inc. and Clinical Laboratories, Inc.

Significant Employee

John M. Johnston (age 40) joined the Company as a petroleum geologist in December 1993 and became Vice President-Exploration and Development in January of 1996. Mr. Johnston specializes in subsurface geological analysis, reservoir engineering, wellsite geology, well completion design and supervision and production maintenance. Mr. Johnston also manages the use of advanced geologic (GeoGraphix) and reservoir engineering (GEMS) computer programs. Before joining the Company, from 1987 through December of 1993, Mr. Johnston served as manager of geology and reservoir engineering for Halwell Company, Inc. of Marietta, Ohio and senior geologist and project manager for Energy Omega, Inc. of Marietta, Ohio, an affiliate of Halwell Company, Inc. From 1981 through 1986, Mr. Johnston worked as a staff exploration geologist for Chevron U.S.A. and Gulf Oil Corp. Mr. Johnston presently is working on his thesis in connection with a Masters of Science Degree in Geology at the University of Cincinnati. Mr. Johnston was awarded a Chevron Fellowship, was a Marathon Oil Scholar and an Edmund J. James Scholar. Mr. Johnston is currently president of the Ohio Geological Society and a member of the board of directors of the Southeastern Ohio Oil and Gas Association. Mr. Johnston is a member of the American Association of Petroleum Geologists, the Society of Professional Well Log Analysts, the Ohio Geological Society and the Ohio Oil and Gas Association.

Board Committees and Meetings

The Company's Board of Directors has two standing committees: the Audit Committee and the Compensation Committee.

Audit Committee. The Audit Committee recommends to the Board of Directors the selection of independent accountants; approves the nature and scope of services to be performed by the independent accountants and reviews the range of fees for such services; confers with the independent accountants and reviews the results of the annual audit; reviews with the independent accountants the Company's internal auditing, accounting and financial controls; and reviews policies and practices regarding compliance with laws and conflicts of interest. Messrs. Yoakley (Chairman) and Walbe currently serve on the Audit Committee and Mr. Remine serves on the Audit Committee as a non-voting member. During 1999, the Audit Committee held one meeting.

Executive Management and Compensation Committee. The Executive Management and Compensation Committee (the "Compensation Committee") is responsible for recommending individuals to serve as officers, reviewing and recommending to the Board of Directors the timing and amount of compensation for the Chief Executive Officer and other key employees, including salaries, bonuses and other benefits. The Compensation Committee also is responsible for administering the Company's stock option and other equity-based incentive plans, recommending retainer and attendance fees for non-employee directors, reviewing for their adequacy and competitiveness compensation plans and awards as they relate to the Chief Executive Officer and other key employees and reviewing management's recommended annual budget and the Company's strategic plans. Messrs. Walbe (Chairman) and

The Board of Directors does not have a standing nominating committee. The Company will consider nominees for election to the Board of Directors submitted by shareholders. The Company's Charter provides that any shareholder entitled to vote generally in the election of directors may nominate one or more persons for election as directors at a meeting only if written notice of such shareholder's intent to make such nomination or nominations has been given to the Secretary of the Company not less than 120 days before the date of notice of the meeting in the case of an annual meeting, and not more than seven days following the date of notice of the meeting in the case of a special meeting. Each such notice to the Secretary shall set forth: (a) the name, age, business address and residence address of each nominee proposed in the notice; (b) the principal occupation or employment of each nominee; (c) the number of shares of capital stock of the Company which are beneficially owned by each nominee; (d) a statement that the nominee is willing to be nominated; and (e) such other information concerning each nominee as would be required under the rules of the Securities and Exchange Commission in a proxy statement soliciting proxies for the election of such nominees.

During the Company's last fiscal year, the Board of Directors held seven regular meetings. Each of the directors attended 75% or more of the aggregate of (a) the total number of meetings of the Board of Directors and (b) the total number of meetings held by all committees of the Board of Directors on which each served (during the periods that each served).

Executive Compensation

Compensation Summary

The following Summary Compensation Table shows certain information concerning the compensation earned during the fiscal years ended December 31, 1999, 1998 and 1997 by the Chief Executive Officer of the Company and each executive officer who earned in excess of $100,000 and who served in positions other than Chief Executive Officer at the end of the last completed fiscal year:

The Company's stock option plans are administered by the Compensation Committee of the Board of Directors which has authority to determine the individuals to whom and the terms upon which options will be granted, the number of shares to be subject to each option and the form of consideration that may be paid upon the exercise of an option. The Board of Directors of the Company makes recommendations of stock incentive grants which the Compensation Committee will then consider.

The following tables list information regarding stock options granted to the named executive officers during the fiscal year ended December 31, 1999:

OPTION GRANTS IN LAST FISCAL YEAR

AGGREGATED OPTION EXERCISES IN LAST FISCAL
YEAR AND FISCAL YEAR-END OPTION VALUES(1)

Charles P. Torrey, Jr., Richard S. Cooper and Robert L. Remine. The Company has entered into employment agreements with Charles P. Torrey, Jr., the Company's Chairman and Chief Executive Officer, Richard S. Cooper, the Company's President, and Robert L. Remine, the Company's Secretary and Treasurer. Each of these employment agreements became effective January 1, 1997, continues for an initial term of five years and is subject to automatic annual renewal terms of one year each year thereafter. Base salary for each of the employment agreements is $180,000 per year, subject to an annual increase of at least 6% per year plus any additional amount that the Board of Directors may award. In addition, in each year in which the gross working interest revenue of the Company increases by at least 20% over its level in the preceding year, each of the employment agreements provides for a yearly performance bonus equal to 25% of the executive officer's base salary.

In December of 1998, the Board of Directors amended the employment agreements of Messrs. Torrey, Cooper and Remine as follows: each individual was entitled to a 1998 cash performance bonus of $47,500 pursuant to their respective employment agreements. In an effort to reduce corporate cash outlays for the Company, an alternative criteria was adopted for payment of the 1998 cash performance payable to Messrs. Torrey, Cooper and Remine. Accordingly, the employment agreements of each individual were amended to provide that: (i) the criteria for determining entitlement to the yearly performance bonus will be growth in Company oil and gas reserves rather than gross working interest revenue; and (ii) the 1998 cash performance bonus will be a $57,000 bonus which will be earned and payable at the sooner of (a) sale of substantially all of the assets of the Company or participation of the Company in a merger or other business combination in which the Company is not the surviving entity, or (b) the 1998 growth in oil and gas reserves benchmark is met and the Company oil and gas reserves for 1999 increase 10% over the prior year.

Messrs. Torrey, Cooper and Remine also were, pursuant to their respective employment agreements, entitled to acquire 1% of any Company well drilled in exchange for payment of 1% of the completion costs of any well selected. The value of the contractual right was estimated to be $75,000 per person. To maximize Company cash flow, management recommended and the Board adopted that the Company purchase from Messrs. Torrey, Cooper and Remine their working interest or right to working interest in Company wells described above for $75,000 payable interest only at the rate of 10% per annum with the principal due and payable at the earlier of three years or the date on which the Company is sold or merged in a transaction in which it is not the surviving entity. The Company made a principal payment of $15,000 and an interest payment of $8,125 to each individual as of December 31, 1999.

Under the employment agreements, Messrs. Torrey, Cooper and Remine also are entitled to receive the following: a nonaccountable automobile allowance of $1,000 per month and reimbursement of itemized fuel, cleaning and related expenses; a life insurance policy in the face amount of $500,000 (with the employee to name the beneficiary) provided the employee is insurable at standard rates (and if extra premiums are incurred to insure the life of the employee, the employee will be responsible for payment of such additional premiums or may accept such reduced death benefit as may be purchased for the cost of standard premiums); medical, health and hospitalization insurance as provided to other executive officers; participation in any bonus or profit-sharing plan, qualified salary deferral plan or pension plan now or in the future adopted by the Company; and three weeks paid vacation.

In the event of Messrs. Torrey's, Cooper's or Remine's termination of employment by the Company with or without cause, each is entitled to be paid a severance allowance equal to 24 months' salary (less amounts required to be withheld and deducted) plus any performance bonus, ratably apportioned. In the event any of Messrs. Torrey, Cooper or Remine are terminated without cause, such termination shall be preceded by 120 days advance written notice. No advance written notice is required to be given by the Company for a termination with cause.

Messrs. Torrey's, Cooper's and Remine's employment agreements each contain confidentiality provisions (generally requiring that all of the Company's confidential and proprietary data be kept confidential) and noncompetition provisions (generally providing that the employee will not directly or indirectly compete with the Company during the term of employment or for two years thereafter) for the benefit of the Company.

Compensation Committee Report on Executive Compensation

The Compensation Committee develops and recommends to the Board of Directors the compensation policies of the Company. The Compensation Committee also administers the Company's compensation plans and recommends for approval by the Board of Directors the compensation to be paid to the Chief Executive Officer and, with the advice of the Board of Directors, the other executive officers of the Company. The Compensation Committee consists of three directors, two of whom are not current or former employees of the Company or its subsidiary and one of whom is a non-voting member and the Company's Chief Executive Officer.

The basic compensation philosophy of the Compensation Committee is to provide competitive salaries as well as competitive incentives to achieve superior financial performance. The Company's executive compensation policies are designed to achieve three primary objectives:

Executive compensation at the Company consists primarily of the following components: base salary and benefits; amounts paid (if any) under the annual bonus programs available to certain executive officers (see below); and participation in the Company's stock option and equity-based incentive plans. Each component of compensation is designed to accomplish one or more of the three compensation objectives described above.

Base Salary

To attract and retain well-qualified executives, it is the Compensation Committee's policy to establish base salaries at levels and provide benefit packages that the Compensation Committee believes to be competitive. Base salaries of executives may be determined in part by comparing each executive's position with similar positions in companies of similar type, size and financial performance. In general, the Compensation Committee has targeted salaries to be commensurate with base salaries paid for comparable positions in comparable size companies. Other factors that have been considered by the Compensation Committee are the executive's performance, the executive's current compensation and the Company's performance (determined by reference to growth revenues from Company oil and gas reserves). The 1999 average base salary of executives increased over the previous year's level as a result of a combination of factors, including improved individual performance, improved performance by the Company and increased responsibilities.

Annual Bonus Program

To provide incentives and rewards for achievement of short-term goals, the Company has entered into employment agreements with Messrs. Torrey, Cooper, Remine and John M. Johnston, the Company's Vice President-Exploration and Development, (the "Executives"). The employment agreements, in addition to providing for employment and base salary, were designed to provide the Executives with the opportunity for bonuses based on the performance of the Company (the "Annual Bonus Program"). The Annual Bonus Program contained in each employment agreement provides that in each year in which the Company's oil and gas reserves increase by at least 20% compared to the level in the preceding year, the Executives will receive a yearly performance bonus equal to 25% of

Discretionary Bonus Plans

In addition to bonuses paid based on corporate performance pursuant to the Annual Bonus Program, the Company also may pay annual incentive bonuses to employees based on individual performance goals. Bonuses based on individual performance will be paid on a discretionary basis, but, generally, only after the review and approval of the Compensation Committee.

Stock Option Plans

Awards under the Company's stock option plans are designed to encourage long-term investment in the Company by participating executives, more closely align executive and shareholder interests and reward executives and other key employees for building shareholder value. The Compensation Committee believes stock ownership by management is beneficial to all shareholders. The Compensation Committee administers all aspects of these plans and reviews, modifies (to the extent appropriate) and takes final action on any such awards.

Under the Stock Option and Restricted Stock Plan of 1998, which previously has been adopted by the shareholders, the Compensation Committee may grant to executives and other key employees shares of restricted stock or rights to purchase stock at a price equal to the value of the stock on the date of grant. These shares are subject to certain restrictions that generally lapse over time.

Under the Company's Stock Option Plan and Stock Option and Restricted Stock Plan of 1998, which previously have been adopted by the shareholders, the Compensation Committee may grant to executives and other key employees options to purchase shares of stock. The Compensation Committee reviews, modifies (to the extent appropriate) and takes final action on the amount, timing, price and other terms of all options granted to employees of the Company. The Compensation Committee is entitled to grant Incentive Stock Options and Nonqualified Options with an exercise price equal to the market price of Common Stock on the date of the grant. Under the terms and conditions of the plans, the Compensation Committee may, however, grant options with an exercise price above or below the market price on the date of grant.

Under the Company's executive officer common stock purchase warrants program (the "Executive Warrants"), the Company has granted warrants to Messrs. Torrey, Cooper and Remine. The exercise price of the Executive Warrants was originally $8.00 per warrant, but this exercise price was reduced to $4.50 per share effective January 1, 1999. The Executive Warrants may be exercised at any time within five years from the date of vesting.

In determining the number of shares of restricted stock and/or the number of options to be awarded to an executive, the Compensation Committee generally considers the levels of responsibility and compensation practices of similar companies. The Compensation Committee also considers the recommendations of management (except for awards to the Chief Executive Officer), the individual performance of the executive and the number of shares previously awarded to and exercised by the executive. As a general practice, both the number of shares granted and their proportion relative to the total number of shares granted increase in some proportion to increases in each executive's responsibilities.

Chief Executive Officer

The Chief Executive Officer's compensation is based upon the policies and objectives discussed above.

Effective January 1, 1997, the Company executed an employment agreement (the "Employment Agreement") with Mr. Torrey which provides for his continued service to the Company through December 31, 2002 (with evergreen provisions), as Chief Executive Officer. The Employment Agreement also is described in this Proxy Statement under the heading "Employment Contracts and Termination of Employment and Change in Control Arrangements."

Under the Employment Agreement, Mr. Torrey will receive a base salary in 2000 of $214,382. This amount is subject to an annual increase of at least 6% per year plus any additional amount that the Board of Directors may

Mr. Torrey's annual incentive bonus under the Annual Bonus Program is based upon the Company increasing its oil and gas reserves by 20% over the level reported for the prior fiscal year. Since the Company achieved the target provided in the Employment Agreement, the Compensation Committee recognized that Mr. Torrey was entitled to a 1998 annual bonus. See "Employment Contracts and Termination of Employment and Change in Control Arrangements" for a description of an amendment to the payment terms of the 1998 annual bonus.

In 1999, Mr. Torrey was awarded options to purchase an additional 44,486 shares of Common Stock.

During 1999, Mr. Torrey's base salary was commensurate with base salaries paid by similar companies to chief executive officers. Due to the Company's 1999 results, the Company believes that Mr. Torrey's salary and bonus and his total compensation were commensurate with amounts paid to chief executive officers by similar companies.

All actions of the Compensation Committee attributable to 1999 compensation were unanimously approved by the Board of Directors.

Compensation of Directors

Directors who are not employees of the Company receive a $3,000 annual retainer fee, $500 for each meeting of the Board that the director attends and an annual grant of 1,000 shares of restricted common stock. In January of 2000, Messrs. Yoakley and Walbe were issued 1,000 shares of restricted stock each pursuant to the Company's Stock Option and Restricted Stock Plan of 1998. Directors who also are employees of the Company or its subsidiary receive no annual retainer and are not compensated for attendance at Board or committee meetings. The Company also reimburses directors for expenses associated with attending Board and committee meetings.

Security Ownership of Certain Beneficial Owners and Management

Security Ownership of Certain Beneficial Owners

The following lists information as to each individual known to us to have been the beneficial owner of more than 5% of outstanding shares of our common stock as of April 24, 2000. The address of each individual listed below is c/o Energy Search, Incorporated, 280 Fort Sanders West Boulevard, Suite 200, Knoxville, Tennessee 37922.

The following table lists the number of shares of our common stock beneficially owned as of April 24, 2000 by each of our directors and nominees for director, each of the named executive officers and all of our directors and executive officers as a group :