ENERGY SEARCH INC, 10KSB, 2000-03-30

ENERGY SEARCH INC
10KSB, 2000-03-30
DRILLING OIL & GAS WELLS

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U. S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB

[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 1999

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

For the transition period from ____________________ to _____________________

Commission File Number: 001-12679

ENERGY SEARCH, INCORPORATED
(Name of Small Business Issuer in Its Charter)

Tennessee
(State or Other Jurisdiction of
Incorporation or Organization) 62-1423071
(I.R.S. Employer Identification No.)

280 Fort Sanders West Blvd., Suite 200
Knoxville, Tennessee
(Address of Principal Executive Offices) 37922
(Zip Code)

(800) 551-5810
(Issuer's Telephone Number, Including Area Code)

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

Securities registered under Section 12(g) of the Exchange Act: Common Stock, No Par Value

Check whether the issuer has: (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No _______

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. [ ]

The Registrant's total revenues for the fiscal year ended December 31, 1999, were $3,945,013.

As of March 29, 2000, the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant was approximately $16,690,396. This amount is based on the sale price of $5.8125 per share for the Registrant's stock as of such date.

As of March 29, 2000, the Registrant had outstanding 4,463,376 shares of Common Stock, no par value.

Documents Incorporated by Reference

Portions of the Registrant's definitive proxy statement for the Registrant's annual meeting of shareholders to be held on July 16, 2000 are incorporated by reference into Part III of this Report.

Transitional Small Business Disclosure Format (check one): Yes ____ No X

PART I

Item 1. 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. In 1999, we drilled 38 net wells and one coalbed methane well.

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 stock. We continued to implement this strategy through 1999. To date we have acquired assets of 14 of 16 affiliated drilling partnerships and we have made an offer to acquire the assets of the last two affiliated drilling partnerships. 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.

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.

Acquisitions in 1999

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 partnerships have been liquidated and dissolved. As consideration for these acquisitions, we issued 245,480 shares of our common stock and paid $204,133 in cash, which was funded with proceeds from our credit facility with Southern Producer Services, L.P. of Houston, Texas. In connection with the transaction we issued an additional 1,119 shares to a non-employee.

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.

L.P. We issued an aggregate of 165,450 shares of 9% cumulative convertible preferred stock to acquire the interests from these partnerships.

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:

• significant reserve potential

• a well developed company infrastructure of gathering systems and pipelines

• premium pricing and economics

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:

• steam

• process heat and co-generation for industrial uses

• feedstock for chemicals used in fertilizer and gasoline production

• electric generation

• residential and commercial heating

In addition, we believe that deregulation of certain sectors of the natural gas industry, which has resulted in lower prices for natural gas, may increase market demand.

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.

Market for Oil and Natural Gas

General. Our revenues from oil and natural gas operations depend highly on the prices of and demand for our natural gas and oil production. In 1999, prices for both natural gas and oil increased over the 1998 prices. The prices that we receive in any year for natural gas and oil production depend upon numerous factors beyond our control including:

• seasonality

• the condition of the United States economy

• foreign imports of oil and natural gas

• political conditions in other oil and natural gas producing countries

• the actions of the Organization of Petroleum Exporting Countries

• domestic government regulation, legislation and regulatory policies

Decreases in the prices of natural gas and oil, as occurred in 1998 and which could occur in the future, have a negative effect on the carrying value of our proved reserves, revenues, profitability and cash flow.

We have entered into a traditional hedging transaction for the purpose of reducing our exposure to price fluctuations. In June 1999, we entered into a "costless collar" transaction with respect to approximately half of our natural gas production by which we are guaranteed to receive not less than $2.45 per decatherm (approximately $2.65 per Mcf). We continue to diversify our natural gas sales contracts to include fixed rate contracts and variable price contracts to provide additional price volatility protection. In connection with our Southern Producer credit facility, a majority of our natural gas production is marketed through Southern Producer.

Although we are not currently experiencing any involuntary curtailments of our oil or natural gas production, future market, economic and regulatory factors may harm our ability to sell oil or natural gas production. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would materially harm our results of operations.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the oil and gas industry. As is customary in the industry in the case of undeveloped properties, we make little investigation of record title other than a preliminary review of local records at the time of acquisition. We generally investigate and receive a title opinion of legal counsel before we begin drilling operations. If title opinions or other investigations reflect title defects, we, rather than the mineral owner, typically are responsible at our expense to cure any defects. If we were unable to remedy or cure a title defect such that it would not be prudent to begin drilling operations on the property, we could suffer a loss of our entire investment in that property. Our properties are subject to customary royalty, overriding royalty, carried, net profits, working and other similar interests, liens incident to operating agreements, liens for current taxes and other burdens. In addition, our credit facility is secured by our oil and natural gas interests and other properties. We granted an overriding royalty interest of up to 3% to Southern Producer in connection with properties acquired or developed with funds from the credit facility.

Regulation and Environmental Matters

General Regulation. Oil and natural gas exploration, production and related operations are subject to extensive rules and regulations of federal, state and local agencies. Failure to comply with these 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 that we substantially comply with all applicable laws and regulations, because these rules and regulations frequently are amended or interpreted, we cannot predict the future cost or impact of complying with these laws.

Environmental enforcement efforts with respect to natural gas and oil operations recently have increased and we anticipate that regulation will expand and have a greater impact on future natural gas and oil operations. We cannot be sure that future laws and regulations will not harm our exploration for, and production and transmission of, oil and natural gas. Legislation and/or actions of local, state and federal governments could harm us in the future. Management believes that we have complied in all material respects with applicable regulatory requirements of the states in which we operate. We have not received a notice of a material violation or complaint concerning compliance with federal, state or local laws respecting the environment. We cannot be sure, however, that our business operations will not violate environmental laws in the future.

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 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 all of our natural gas and oil properties are located, the Ohio Department of Natural Resources and the West Virginia Division of Environmental Protection Office of Oil and Gas regulate these activities. 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. Ohio and West Virginia also have enacted other pollution and environmental control laws which have become increasingly burdensome in recent years.

Federal Regulation. The availability, terms and cost of transportation affect our sales of natural gas. The price and terms for access to pipeline transportation are subject to extensive regulation. The Federal Energy Regulatory Commission regulates the transportation and sale for resale of natural gas in interstate commerce under 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, the Federal Energy Regulatory Commission 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 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 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. Although Order 636 has largely been upheld on appeal, several appeals remain pending in related restructuring proceedings. We cannot predict when these remaining appeals will be completed or what impact they will have on our business.

The Federal Energy Regulatory Commission has announced several important transportation-related policy statements and proposed rule changes, including a statement of policy and a request for comments concerning alternatives to its traditional cost-of-service ratemaking methodology to establish the rates interstate pipelines may charge for their services. A number of pipelines have obtained authorization from the Federal Energy Regulatory Commission to charge negotiated rates as an alternative. In February 1997, the Federal Energy Regulatory Commission announced a broad inquiry into issues facing the natural gas industry for the purpose of establishing regulatory goals and priorities in the post-Order 636 environment. While the changes being considered by federal and state regulators would affect us only indirectly, they are intended to further enhance competition in natural gas markets. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the Federal Energy Regulatory Commission, state commissions and the courts. The natural gas industry historically has been very heavily

regulated; therefore, we cannot be sure that the less stringent regulatory approach recently pursued by the Federal Energy Regulatory Commission and Congress will continue.

The price that we receive from the sale of oil and natural gas liquids is affected by the cost of transporting products to markets. The Federal Energy Regulatory Commission has implemented regulations establishing an indexing system for transportation rates for oil pipelines. These regulations generally index transportation rates to inflation, subject to certain conditions and limitations. The regulations may increase transportation costs or reduce well head prices for oil and natural gas liquids.

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 we expect this trend to continue. These laws and regulations may do any of the following:

• require the acquisition of a permit or other authorization before construction or drilling commences

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities

• limit or prohibit construction, drilling and other activities on certain lands lying within wilderness, wetlands and other protected areas

• require remedial measures to mitigate pollution from former operations such as plugging abandoned wells

• impose substantial liabilities for pollution resulting from our operations

The permits required for some of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities can enforce compliance with their regulations, and violators are subject to civil and criminal penalties or injunction. Management believes that we substantially comply with current applicable environmental laws and regulations, and that we do not have material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations could harm us, as well as the oil and gas industry in general. Accordingly, we cannot predict the ultimate cost and effects of future compliance.

The Comprehensive Environmental Response, Compensation and Liability Act 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 this act, these persons or companies may be responsible for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. 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 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 the Comprehensive Environmental Response, Compensation and Liability Act 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 the Resource Conservation and Recovery Act classifies certain oil field wastes as "non-hazardous," these exploration and production wastes could be reclassified as hazardous wastes thereby making the 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, the owners may have disposed or released hydrocarbons or other wastes on or under the properties. Accordingly, the treatment and disposal or release of hydrocarbons or other wastes on or under these properties was not under our control. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and Recovery Act and analogous state laws. Notwithstanding our lack of control over properties previously operated by others, the failure of these operators to comply with applicable environmental regulations may, in certain circumstances, harm our business.

The Federal Clean Water Act and analogous state laws require companies to obtain permits to discharge materials into surface waters or to construct facilities in wetland areas. With respect to certain operations, we are required to maintain these permits or meet general permit requirements. The Environmental Protection Agency 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 Environmental Protection Agency general permit. We believe that we can obtain, or be included under, these permits where necessary, and to make minor modifications to existing facilities and operations. We do not expect that obtaining these permits and modifying existing facilities and operations as required will materially harm our business.

Competition

The oil and natural gas industry is highly competitive in all of its phases. We compete with many other companies in the search for and acquisition of oil and natural gas properties and leases for exploration and development. 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 we do and have been in the exploration and production business for a much longer time than we have. These 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 permit. We will be required to maintain and enhance our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in a highly competitive environment. We expect competition among oil and natural gas companies for favorable oil and natural gas prospects to continue. We anticipate that the cost of purchasing oil and natural gas properties may increase appreciably.

Operating Hazards and Uninsured Risks

Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. We cannot be sure that new wells drilled by us will be productive or that we will recover all or any portion of our investment. 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 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
	•	shortages or delays in the delivery of equipment and services

Our future drilling activities may not be successful and, if unsuccessful, could harm our future results of operations and financial condition.

Our operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, including:

• 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 the above factors could cause a loss of hydrocarbons, environmental pollution, personal injury claims and other damage to properties. We are insured against some but not necessarily all of the risks described above. In particular, our insurance 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 high compared 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 harm our business, financial condition and results of operations.

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 23 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.

Activities with Affiliated Drilling Partnerships

We operate approximately 229 miles of gas gathering systems which service our primary areas of operation in Ohio and West Virginia. Approximately 92 miles of the gas gathering systems was owned by a Tennessee limited partnership. In the fourth quarter of 1999, we acquired all of the investor limited partner interests of the partnership in exchange for shares of our preferred stock.

From 1989 to 1998 we sponsored 16 affiliated drilling partnerships. We did not sponsor an affiliated drilling partnership in 1999 and do not plan to sponsor any partnerships in the future. Beginning in 1998, we implemented a consolidation strategy to reacquire interests in wells from affiliated drilling partnerships for cash or shares of our stock. To date, we have acquired assets of 14 of 16 affiliated drilling partnerships and we have made an offer to acquire the assets of the last two affiliated drilling partnerships.

Activities of Equity Financial Corporation

Equity Financial Corporation, our wholly owned subsidiary, is a securities brokerage firm and member of the National Association of Securities Dealers. Equity Financial is engaged primarily in the business of providing investment services and products to its clients. Charles P. Torrey, Jr., our Chief Executive Officer, and Robert L. Remine, our Chief Financial Officer, are each licensed agents and principals of Equity Financial and founded that company in 1985. Equity Financial has seven additional licensed sales agents and maintains offices adjacent to our offices in Knoxville, Tennessee.

At times, Equity Financial has served as placement agent for the private placement of our securities, including common stock, preferred stock and partnership interests in affiliated drilling partnerships. For these services, Equity Financial has received placement fees and sales commissions. We believe these fees and commissions are consistent with requirements of the National Association of Securities Dealers and similar to fees and commissions that would be charged by unrelated firms performing similar services.

Item 2. 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 the date of this Form 10-KSB, our net paid production of natural gas exceeds 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 and have drilled 11 natural gas wells in 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 and drilled one well in 1999.

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 it 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

at December 31,

1999
1998
1997

Company - Total

Total Proved Reserves:⁽¹⁾

        Oil (Bbls)
481,238

44,554

23,624

        Natural Gas (Mcf)
60,747,920

43,493,054

30,609,977

        Equivalent Bbls (BOE)⁽²⁾
10,605,891

7,293,396

5,125,287

        Equivalent Mcf (Mcfe)⁽²⁾
63,635,348

43,760,378

30,751,721

Total Proved Undeveloped Reserves:⁽¹⁾

        Oil (Bbls)
257,067

--

--

        Natural Gas (Mcf)⁽²⁾
35,027,540

27,502,100

19,417,960

        Equivalent Bbls (BOE)⁽²⁾
6,094,990

4,583,683

3,236,327

        Equivalent Mcf (Mcfe)⁽²⁾
36,569,942

27,502,100

19,417,960

Total Proved Developed Reserves:⁽¹⁾

        Oil (Bbls)
224,171

44,554

23,624

        Natural Gas (Mcf)
25,720,380

15,990,954

11,192,017

        Equivalent Bbls (BOE)⁽²⁾
4,510,901

2,709,713

1,888,960

        Equivalent Mcf (Mcfe)⁽²⁾
27,065,406

16,258,278

11,333,761

__________________________

(1) Reserves are net to our interest. Applicable royalties have been deducted from these volumes.

(2) After conversion on the basis of 6.0 Mcf of natural gas to 1.0 barrel of crude oil.

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 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

at December 31,

1999
1998
1997

Company - Total

Proved Developed Producing

        Oil (Bbl)
224,171

44,554

23,624

        Natural Gas (Mcf)
20,367,120

14,589,660

7,475,526

Proved Developed Non-Producing

        Oil (Bbl)
--

--

--

        Natural Gas (Mcf)
5,353,260

1,401,294

3,716,491

Proved Undeveloped

        Oil (Bbl)
257,067

--

--

        Natural Gas (Mcf)
35,027,540

27,502,100

19,417,960

Estimated Future Net Cash Flows

   Before Income Taxes

        Proved Producing
$

52,932,740

$

30,863,380

$

20,212,160

        Proved Non-Producing
13,101,276

2,452,715

9,575,898

        Proved Undeveloped
79,067,480

44,136,160

41,354,112

                Total
$

145,101,496

$

77,452,255

$

71,142,170

Estimated Future Net Cash Flows

   Before Income Taxes Discounted at 10%

        Proved Producing
26,016,110

$

15,852,520

$

9,703,797

        Proved Non-Producing
5,960,000

8,761,363

4,748,113

        Proved Undeveloped
27,751,440

14,032,700

17,909,290

                Total
$

59,727,550

$

30,761,583

$

32,361,200

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 Form 10-KSB.

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 Form 10-KSB 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 Form 10-KSB 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

Oil
Natural Gas
Total

Region
Gross
Net
Gross(1)
Net
Gross
Net

Ohio
45

45

464

453

509

498

West Virginia
1

1

54

54

55

55

Total
46

46

518

507

564

553

___________________

(1) Of the wells reported, 329 gross wells had multiple completions or were producing from more than one geological formation.

Production Volumes, Average Prices and Production Costs

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.

at December 31,

1999
1998
1997

Net Production:

        Oil (Bbls)
23,133

7,859

1,158

        Natural Gas (Mcf)
1,186,863

1,045,201

321,264

        Total (BOE)
220,943

182,059

54,702

        Total (Mcfe)
1,325,661

1,092,355

328,212

Average Sales Price:

        Oil ($/Bbl)
$

19.73

$

11.74

$

18.06

        Natural Gas ($/Mcf)
2.49

2.41

2.43

Average Production Lifting Cost:

         ($/Mcfe)⁽¹⁾
$

.74

$

.61

$

.84

____________________________

(1) Includes direct lifting costs, such as labor, repairs and maintenance, materials and supplies, and property and severance taxes.

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 Form 10-KSB 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:

Year Ended December 31,

1999
1998
1997

Development Costs
$ 6,810,971

$

6,607,991

$

5,683,356

Exploration Costs
76,815

218,369

84,616

Property Acquisition Costs
3,221,780

4,560,556

1,535,173

Recent Drilling Activities

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.

Year Ended December 31,

1999
1998
1997

Gross
Net
Gross
Net
Gross
Net

Ohio

Development Wells

Oil
0.0

0.0

0.0

0.0

0.0

0.0

Natural Gas
21.0

21.0

16.0

15.7

8.0

3.8

Dry
2.0

2.0

0.0

0.0

0.0

0.0

Total
23.0

23.0

16.0

15.7

8.0

3.8

Exploratory Wells

Oil
0.0

0.0

0.0

0.0

0.0

0.0

Natural Gas
1.0

1.0

0.0

0.0

1.0

0.1

Dry
0.0

0.0

0.0

0.0

0.0

0.0

Total
1.0

1.0

0.0

0.0

1.0

0.1

West Virginia

Development Wells

Oil
0.0

0.0

0.0

0.0

0.0

0.0

Natural Gas
13.0

13.0

4.0

4.0

24.0

20.1

Dry
1.0

1.0

0.0

0.0

3.0

3.0

Total
14.0

14.0

4.0

4.0

27.0

23.1

Exploratory Wells

Oil
0.0

0.0

0.0

0.0

0.0

0.0

Natural Gas
1.0

1.0

0.0

0.0

1.0

1.0

Dry
0.0

0.0

0.0

0.0

0.0

0.0

Total
1.0

1.0

0.0

0.0

1.0

1.0

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

Developed
Undeveloped
Total

Region
Gross
Net
Gross
Net
Gross
Net

Ohio
48,005

47,441

31,194

31,194

79,199

78,635

West Virginia
20,039

19,635

90,881

85,421

110,920

105,056

Total
68,044

67,076

122,075

116,615

190,119

183,691

For purposes of the above table, developed acreage means acreage that is held by existing production, has no further drilling obligations or delay rentals due and embodies, in its aggregate, offsetting drilling locations.

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%.

Item 3. Legal Proceedings.

We routinely are engaged in litigation as plaintiff and defendant in the normal course of business. In the opinion of management, all litigation matters are not expected to materially affect our consolidated financial position, operating results or cash flows.

Item 4. Submission of Matters to a Vote of Security Holders.

During the fourth quarter of 1999, we did not submit any matter to a vote of security holders, through the solicitation of proxies or otherwise.

PART II

Item 5. Market For Common Equity and Related Stockholder Matters.

Our common stock is quoted on the Nasdaq SmallCap Market under the ticker symbol "EGAS."

The following table lists the high and low sale prices for our common stock for the periods indicated, all as reported by the Nasdaq SmallCap Market:

		High		Low
Year Ended December 31, 1999:
First Quarter	$	5.31	$	3.69
Second Quarter		4.88		3.75
Third Quarter		4.69		3.81
Fourth Quarter		5.38		4.00

Year Ended December 31, 1998:
First Quarter	$	10.25	$	9.00
Second Quarter		11.00		8.88
Third Quarter		9.25		5.25
Fourth Quarter		6.94		4.38

The estimated number of record holders of our common stock was approximately 2,000 as of March 29, 2000.

We have not paid any dividends on our common stock and do not expect to declare cash dividends on the common stock in the foreseeable future. However, we have issued 769,517 shares of 9% redeemable convertible preferred stock on which we pay dividends quarterly. Other than dividends payable on the 9% redeemable convertible preferred stock, out bank notes restrict our ability to pay dividends.

In July of 1999 we issued 4,000 shares of common stock to our legal counsel in connection with advisory services rendered. This issuance occurred under our 1998 Stock Option and Restricted Stock Plan for Outside Market Advisors. The issuance of these shares was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder.

Item 6. Management's Discussion and Analysis or Plan of Operation.

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

This Form 10-KSB 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, performance or achievements may differ materially from the results, performance or achievements discussed in the forward-looking statements. There are numerous factors that could cause actual results to differ materially from the results discussed in forward-looking statements, including:

• the impact that the following factors can have on our business and the energy resource industry in general:

• lack of product diversity: our reliance on natural gas could place us at a disadvantage with respect to our competitors that are more diversified; this situation could arise if, for example, natural gas prices fell while other energy commodity prices rose

• lack of geographical diversity: due to our concentration in the Appalachian Basin, we are susceptible to regional factors that may place us at a disadvantage relative to our competitors; these regional factors include: regional disasters, such as tornadoes, floods and wind storms; or particularly harmful changes in state or local laws

• changes in competition and pricing environments: if competition increases in segments of the energy resource industry, larger companies with greater capital reserves and greater diversification may have more options at their disposal for handling increased competition than we do

• potential negative side effects stemming from our shift away from our joint ventures with affiliated drilling partnerships: as a result of this shift, our capitalization strategies have evolved, and our current strategy necessarily involves pitfalls that we, being relatively new to this type of capitalization, may fail to recognize due to lack of experience

• the timing and extent of our success in discovering, acquiring, developing and producing natural gas and oil resources

• risks incident to the drilling and operation of natural gas and oil wells

• changes in future production development costs

	•	regulatory issues in the securities sector: unforeseen or harsh regulations have the potential of harming Equity Financial, our wholly owned subsidiary; these changes can therefore impact us indirectly

	•	inaccuracies inherent in modern methods of estimating underground reserves: differences between these estimates and the actual amount of reserves could impair any plans or forecasts that we made based on the estimates

•	changes in existing energy resource industry laws or the introduction of new laws, regulations or policies that could affect our business practices: these laws, regulations or policies could impact the energy industry as a whole, or could impact only those portions of the energy resource industry in which we are currently active, for example, laws regulating natural gas; in either case, our profitability could be injured due to an industry-wide market decline or due to our inability to compete with other energy resource industry companies that are unaffected by these laws, regulations or policies

•	changes in environmental regulations: these laws could be harmful if they:

	•	impact the energy resource industry as a whole, causing market decline

	•	impact those segments of the economy upon which we rely heavily, such as natural gas

	•	are concentrated in regions within which we conduct a large percentage of our business, such as the Appalachian Basin

•	changes in economic conditions, including changes in interest rates, financial market performance and the energy resource industry: these types of changes can impact the economy in general, resulting in a downward trend that impacts not only our business, but all energy resource industry companies; or, the changes can impact only those parts of the economy upon which we rely in a unique fashion, including, by way of example:

	•	economic factors that affect our credit financing relationship with Southern Producer

	•	prices of relevant commodities: these prices can, of course, be affected not only by matters outside of our control, but also by matters entirely outside of the control of the United States, such as actions of the Organization of Petroleum Exporting Countries

	•	commodity price shifts: we utilize a natural gas price hedging tactic; however, we may still be sensitive to price fluctuations despite these efforts

	•	economic factors that may affect the success of the acquisition strategy that we pursued in 1999

•	factors that we have discussed in previous public reports and other documents filed with the Securities and Exchange Commission

This list provides examples of factors that could affect the results described by forward-looking statements contained in this Form 10-KSB. 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 Form

10-KSB are reasonable, we cannot provide you with any guarantee that the anticipated results will be achieved. All forward-looking statements in this Form 10-KSB 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 Form 10-KSB. 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 and the subsequent drilling development, exploitation and exploration of these properties, resulting in significant increases in our reserves and production. In 1999, 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. In 1999, we drilled 38 net wells and one coalbed methane well. According to the year-end reserve report of our independent certified petroleum engineers, Wright & Company, Inc., as of December 31, 1999 we had proven natural gas reserves of approximately 63.6 Bcfe with a 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 values have increased 93.8% in 1999 compared to 1998 due to our proven reserve growth and an increase in the price of the natural gas and oil commodities.

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. This credit facility has a credit limit of $30,000,000, upon which $18,019,344 was drawn down as of December 31, 1999. The 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 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 credit facility principally to retire approximately $8,769,776 in bank debt, to acquire oil and gas properties and to fund the drilling of our wells in Ohio and West Virginia. The credit facility is accompanied by a preferred gas marketing arrangement whereby Southern Producer has the first option to purchase and market all natural gas produced from our wells, provided it can do so on purchase terms no less favorable than we could obtain marketing our own natural gas.

In connection with the 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.

Events Subsequent to December 31, 1999

In March of 2000, we closed the purchase of approximately 6,500 acres of oil and gas properties from Cabot Oil & Gas Corporation for a purchase price of $1,600,000. The property is contiguous to our existing field in Raleigh County, West Virginia and includes 45 producing wells and related gas gathering equipment. 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 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. We expect to complete this offering in the second quarter of 2000.

Year Ended December 31, 1999 Compared to the Year Ended December 31, 1998

Financial Condition

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 Southern Producer 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. The net increase in cash of $646,346 is due primarily to a decrease in the collection time of oil and gas accounts receivable. Effective in the fourth quarter of 1999, Southern Producer agreed to purchase approximately 60% of our 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. At December 31, 1999, oil and gas revenues of approximately $622,000 were in the restricted cash account maintained by Southern Producer. 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 December 31, 1998 to $119,047 or 31.9% for the year ended December 31, 1999 due primarily to an increase in prepaid expenses of $12,700 and inventory of $16,100.

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 depreciation, depletion and amortization rates. Oil and gas producing 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 leases 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, intangible drilling costs associated with the company-drilled wells of approximately $4,028,869 and the capitalization of certain costs directly related to drilling our wells of approximately $1,297,910.

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% cumulative convertible preferred stock, $4.00 par value, to limited partners in the Energy Search Natural Gas Pipeline Income L.P. 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 from an 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% cumulative convertible preferred stock to acquire the interests from these partnerships. Management determined that we had an impairment in our receivable from an 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 Southern Producer credit facility should permit us to drill approximately 75 wells in 2000. In October of 1999, we closed the purchase of producing properties (99 wells) and certain undeveloped acreage located in Lawrence, Vinton and Gallia Counties, Ohio, from Mitchell Energy Corporation utilizing proceeds from the Southern Producer credit facility. The effective date of this transaction was June 1, 1999.

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 the elimination of approximately $1,641,700 in investment accounts and amounts due from related partnerships in the amount of approximately $68,500. 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.

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 Southern Producer credit facility which has an aggregate credit limit of $30,000,000. The 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 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 decrease 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 Southern Producer 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, a decrease 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 Southern Producer 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.

Results of Operations

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 BO per day in 1998 to approximately 63.3 BO 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 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 turnkey revenue compared to the $67,312 of turnkey revenue 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. 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, increased production of net wells that we now own and increased amortization rates with respect to certain well equipment and 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 receivables from investments in the partnership 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, to a lesser extent, 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. This increase is due to management's belief that we will have sufficient taxable income from operations and financing to use the net operating loss carryforwards and realize the entire deferred tax asset. 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.

Cash Flow from Operations, Investing and Financing Activities

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 Southern Producer 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 in the amount of $2,079,259 and to fund operations and developmental drilling on oil and gas properties in Ohio and West Virginia in the amount of approximately $7,115,342. 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 $847,707. The majority of these funds were used for the development of our Beaver Lease and Churchtown Lease areas, enhancement efforts and development of the Simmons field, the purchase of oil and gas wells and associated leases and equipment from Viking Resources Corporation and the purchase of working interests and overriding royalty interests from certain individuals and the affiliated drilling partnerships.

Liquidity and Capital Resources

The primary source of funds has been cash flow from operations of $488,217, borrowing against the Bank One credit facility, before the Southern Producer refinancing, of $1,020,000 and borrowing against the Southern Producer credit facility of $18,019,344. The proceeds from these sources have been used to pay the preexisting Bank One credit facility in full and to fund our operations 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 the Southern Producer credit facility with a credit limit of $30,000,000 and upon which $18,019,344 was drawn down as of December 31, 1999. The Southern Producer 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. Southern Producer also received warrants to purchase 100,000 shares of our common stock at $6.50 per share. The Southern Producer credit facility is accompanied by a preferred gas marketing arrangement which gives Southern Producer the first option to purchase and market all natural gas produced from our wells, provided it can do so on purchase terms no less favorable than we could obtain if we marketed our own natural gas.

We also have a note payable to SunTrust Bank with an outstanding principal balance of $438,053 as of December 31, 1999, collateraized 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, debt to tangible net worth, limits on partnership subsidies, restrictions on payment of dividends and general and administrative expenses. We were in compliance with these covenants at December 31, 1999.

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 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.

Year 2000 Readiness Disclosure

As of the filing date of this Annual Report on Form 10-KSB, we have not experienced any Year 2000 issues arising from our systems or those of our material vendors and suppliers. If there are any ongoing Year 2000 issues that might arise at a later date, we have contingency plans in place to address these issues. We continue to maintain contact with third parties with whom we have material relationships, such as vendors, suppliers and financial institutions, with respect to the third parties' Year 2000 compliance and any ongoing Year 2000 issues that might arise at a later date.

We have incurred costs of less than $25,000 related to identifying, assessing, remediating and testing Year 2000 issues and do not expect to incur material costs in the future. These costs have consisted primarily of personnel expense for employees who have had only a portion of their time dedicated to the Year 2000 remediation effort. We have funded these costs through operating cash flows and have expensed the costs as incurred.

In light of our efforts, the Year 2000 issue has not materially harmed our business or results of operations. However, we cannot be sure that we or any third parties will not have ongoing Year 2000 issues that could harm our business, operating results and financial condition.

Item 7. Financial Statements.

The Consolidated Financial Statements and related notes begin on Page F-1 of this Form 10-KSB.

Item 8. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

PART III

Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance With Section 16(a) of the Exchange Act.

The information contained under the headings "Board of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our Definitive Proxy Statement for the annual meeting of shareholders to be held on July 16, 2000 is here incorporated by reference.

Item 10. Executive Compensation.

The information contained under the headings "Compensation of Directors," "Executive Compensation," "Employment Contracts and Termination of Employment and Change in Control Arrangements" and "Compensation Committee Report on Executive Compensation" in our Definitive Proxy Statement for the annual meeting of shareholders to be held on July 16, 2000 is here incorporated by reference.

Item 11. Security Ownership of Certain Beneficial Owners and Management.

The information contained under the headings "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Management" in our Definitive Proxy Statement for the annual meeting of shareholders to be held on July 16, 2000 is here incorporated by reference.

Item 12. Certain Relationships and Related Transactions.

The information contained under the heading "Certain Relationships and Related Transactions" in our Definitive Proxy Statement for the annual meeting of shareholders to be held on July 16, 2000 is here incorporated by reference.

Item 13. Exhibits and Reports on Form 8-K.

Item 13(a). Exhibits

Exhibits

Exhibit
Number Description

3.1 Fourth Amended and Restated Charter of the Registrant(1)

3.2 Articles of Amendment to Charter (2)

3.3 Bylaws of the Registrant(3)

4.1 Specimen of Common Stock Certificate(4)

4.2 Specimen of Redeemable Series A Common Stock Purchase Warrant Certificate(4)

4.3 Specimen of Underwriters' Warrant Certificate(4)

4.4 Charter (See Exhibits 3.1 and 3.2)

4.5 Bylaws (See Exhibit 3.3)

9.1	Shareholder Voting Agreement and Irrevocable Proxy(4)
10.1	Energy Search Natural Gas 1995-A L.P. Limited Partnership Agreement, dated March 31, 1995(4)
10.2	Energy Search Natural Gas 1995-A L.P. Joint Drilling and Operating Agreement, dated March 31, 1995(4)
10.3	Energy Search Natural Gas 1996 L.P.-Limited Partnership Agreement, dated September 10, 1996(4)
10.4	Energy Search Natural Gas 1996 L.P.-Joint Drilling and Operating Agreement, dated September 10, 1996(4)
10.5	ESI Pipeline Operating Partnership-Limited Partnership Agreement, dated January 7, 1993(4)
10.6	Energy Search Natural Gas Pipeline Income Partnership-Limited Partnership Agreement, dated January 7, 1993(4)
10.7	Gas Servicing Agreement between the Registrant and ESI Pipeline Operating L.P., dated January 5, 1993(4)
10.8	Selling Agreement-Class B Convertible Preferred Shares between Registrant and Equity Financial Corporation, dated March 4, 1996(4)
10.9	Selling Agreement-Class A and Class B Preferred Shares between Registrant and Equity Financial Corporation, dated March 4, 1996(4)
10.10	Selling Agreement-Variable Rate Subordinated Debentures between Registrant and Equity Financial Corporation, dated September 19, 1994(4)
10.11	Aircraft Lease between Charles P. Torrey, Jr. and the Registrant dated February 1, 1995(4)
10.12	Beaver Coal Company Lease between Beaver Coal Company Limited and the Registrant, dated September 15, 1996(4)
10.13	Amended and Restated Employment Agreements with officers and key employees of the Registrant: (a) John M. Johnston(5)* (b) Robert L. Remine(5)* (c) Charles P. Torrey, Jr.(5)* (d) Richard S. Cooper(5)*
10.14	Promissory Notes of Executive Officers in Favor of Registrant: (a) Charles P. Torrey, Jr.(4) (b) Robert L. Remine(4) (c) Richard S. Cooper(4)
10.15	Stock Option Plan(4)*
10.16	Outside Directors' Stock Option Plan(4)*
10.17	Form of Lock-Up Agreement(4)
10.18	Stock Option and Restricted Stock Plan of 1998, as amended(6)*
10.19	Form of Indemnification Agreement (1)*
10.20	1998 Stock Option and Restricted Stock Plan for Outside Advisors and Consultants(7)
10.21	Credit Agreement between the Registrant and Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.22	First Amendment to Credit Agreement between the Registrant and Southern Producer Services, L.P., dated as of October 21, 1999(5)
10.23	Form of Note in the amount of $30,000,000 payable to Southern Producer Services, L.P., dated June 23, 1999(5)
10.24	Mortgage, Deed of Trust, Assignment, Security Agreement and Financing Statement from the Registrant to Brian P. Shannon, David W. Stewart and Southern Producer Services, L.P., dated as of June 23, 1999(5)

10.25	Credit Line Deed of Trust, Assignment of Production, Security Agreement and Financing Statement from the Registrant to William C. Martin, trustee, and Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.26	Pledge Agreement made by the Registrant in favor of Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.27	Warrant to Purchase Common Stock of the Registrant, expiring June 23, 2004(5)
10.28	Assignment and Conveyance of Overriding Royalty Interest between the Registrant and Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.29	Base Contract for Short-Term Sale and Purchase of Natural Gas between the Registrant and Southern Producer Services, L.P.(5)
11.1	Statement Regarding Computation of Earnings Per Common Share
21.1	Subsidiaries(8)
23.1	Consent of Experts and Counsel (a) Consent of Independent Accountant, Plante & Moran, LLP, CPA (b) Consent of Independent Petroleum Consultant, Wright & Company, Inc.
27.1	Financial Data Schedule

____________________________

* Management contract or compensatory plan or arrangement

(1) Previously filed with our Definitive Proxy Statement filed on April 28, 1998 with the Securities and Exchange Commission, and here incorporated by reference.

(2) Previously filed with our Form 10-QSB for the quarter ended June 30, 1999, and here incorporated by reference.

(3) Previously filed with our Form 10-QSB for the quarter ended June 30, 1998, and here incorporated by reference.

(4) Previously filed with our Registration Statement on Form SB-2 (Registration No. 333-12755) filed with the Securities and Exchange Commission, and here incorporated by reference.

(5) Previously filed with our Form 10-QSB for the quarter ended September 30, 1999, and here incorporated by reference.

(6) Previously filed with our Definitive Proxy Statement filed on April 30, 1999 with the Securities and Exchange Commission, and here incorporated by reference.

(7) Previously filed with our Form 10-QSB Quarterly Report for the quarter ended September 30, 1998, and here incorporated by reference.

(8) Previously filed with our Form 10-KSB Annual Report for the fiscal year ended December 31, 1997, and here incorporated by reference.

Item 13(b). Reports on Form 8-K

We did not file any reports on Form 8-K during the fourth quarter of 1999.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: March 30, 2000
ENERGY SEARCH, INCORPORATED

/s/ Richard S. Cooper
Richard S. Cooper

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title Date

/s/ Charles P. Torrey, Jr.
Charles P. Torrey, Jr. Chief Executive Officer and Director
(Principal Executive Officer) March 30, 2000

/s/ Richard S. Cooper
Richard S. Cooper President and Director March 30, 2000

/s/ Robert L. Remine
Robert L. Remine
Secretary, Treasurer and Director
(Principal Financial and Accounting
Officer)
March 30, 2000

Energy Search, Incorporated and Subsidiary

Consolidated Financial Report

with Additional Information

December 31, 1999

F-1

Contents

Report Letter	F-3

Financial Statements

Consolidated Balance Sheet	F-4

Consolidated Statement of Operations	F-5

Consolidated Statement of Shareholders' Equity	F-6

Consolidated Statement of Cash Flows	F-7

Notes to Consolidated Financial Statements	F-8 to F-23


Supplementary Information	F-24


Report Letter	F-25

Cost Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities	F-26

Estimates of Natural Gas and Oil Reserves	F-26 to F-28

F-2

Independent Auditor's Report

To the Shareholders of
Energy Search, Incorporated and Subsidiary

We have audited the accompanying balance sheet of Energy Search, Incorporated and Subsidiary, (the Company) as of December 31, 1999 and 1998 and the related statements of operations, shareholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Energy Search, Incorporated and Subsidiary, as of December 31, 1999 and 1998 and the results of its operations and its cash flows for the years then ended, in conformity with generally accepted accounting principles.

Grand Rapids, Michigan
March 17, 2000

F-3

Energy Search, Incorporated and Subsidiary

Consolidated Balance Sheet

		December 31,
		1999		1998
Assets
Current Assets
Cash and cash equivalents	$	407,878	$	595,749
Restricted cash (Note E)		834,217		--
Accounts receivable (Note I)		781,542		980,881
Other current assets		119,047		90,226
Total current assets		2,142,684		1,666,856

Oil and Gas Properties
Proven properties		21,279,899		13,165,858
Unproven properties		235,281		209,616
Wells and related equipment		15,028,699		11,357,198
Less accumulated depreciation, depletion and amortization		(6,725,182	)	(4,467,912	)
Net oil and gas properties		29,818,697		20,264,760

Other Assets
Other property and equipment, Net (Note C)		287,035		287,746
Investments in related partnerships (Note B)		3,020		1,713,267
Deferred tax asset (Note D)		1,108,300		886,000
Other		528,191		204,780
Total other assets		1,926,546		3,091,793
Total assets	$	33,887,927	$	25,023,409

Liabilities and Shareholders' Equity
Current Liabilities
Current portion of long-term debt (Note E)	$	2,337,373	$	546,407
Accounts payable and accrued liabilities		1,104,865		632,677
Total current liabilities		3,442,238		1,179,084

Long-Term Debt - less current portion (Note E)		16,300,024		7,703,369

Shareholders' Equity (Notes F, G, H and J)
Preferred stock: no par value, 5,000,000 shares authorized;
769,517 and 175,547 shares of 9% redeemable
convertible issued and outstanding at December 31, 1999 and 1998, respectively		1,439,311		847,707
Common stock: no par value, 25,000,000 shares authorized;
4,356,376 and 4,017,308 shares issued and outstanding
at December 31, 1999 and 1998, respectively		17,934,838		17,206,862
Accumulated deficit		(5,228,484	)	(1,913,613	)
Total shareholders' equity		14,145,665		16,140,956
Total liabilities and shareholders' equity	$	33,887,927	$	25,023,409

See Notes to Consolidated Financial Statements.

F-4

Energy Search, Incorporated and Subsidiary

Consolidated Statement of Operations

		Year Ended December 31,
		1999			1998
Revenue
Oil and gas sales	$	3,391,770		$	2,597,875
Management fees (Note I)		71,100			145,586
Net turnkey revenue		--			67,312
Other revenue (Note L)		445,928			609,725
Total revenue		3,908,798			3,420,498

Operating Expenses
Production costs		972,799			661,036
Exploration costs		51,150			202,718
Depreciation, depletion and amortization		2,511,266			1,551,685
Impairment charges (Note F)		688,663			--
Interest		1,059,231			392,716
General and administrative		2,010,177			1,156,890
Total operating expenses		7,293,286			3,965,045

Net (Loss) from Operations		(3,384,488	)		(544,547	)

Other Income (Expense)
Program subsidies (Note I)		(104,303	)		(192,837	)
Equity in income of related partnerships (Note B)		36,215			107,356
Total other income (expense)		(68,088	)		(85,481	)

Net (Loss) Before Income Taxes		(3,452,576	)		(630,028	)

Income Tax Benefit (Note D)		224,600			235,600

Net (Loss)	$	(3,227,976	)	$	(394,428	)

Basic Net (Loss) Per Common Share	$	(0.79	)	$	(0.11	)

Diluted Net (Loss) Per Common Share	$	(0.79	)	$	(0.11	)

See Notes to Consolidated Financial Statements.

F-5

Energy Search, Incorporated and Subsidiary

Consolidated Statement of Shareholders' Equity

	Preferred Stock			Common Stock
	Shares		Amount	Shares		Amount		Accumulated Deficit			Total

Balance - January 1, 1998	--	$	--	3,768,241	$	15,448,073	$	(1,501,584	)	$	13,946,489

Issuance of common stock (Note G)	--		--	249,067		1,758,789		--			1,758,789

Issuance of preferred stock (Note F)	175,547		847,707	--		--		--			847,707

Dividends on redeemable convertible
preferred stock	--		--	--		--		(17,601	)		(17,601	)

Net loss for the year ended December 31, 1998	--		--	--		--		(394,428	)		(394,428	)

Balance - December 31, 1998	175,547		847,707	4,017,308		17,206,862		(1,913,613	)		16,140,956

Issuance of common stock (Note G)	--		--	339,068		727,976		--			727,976

Issuance of preferred stock (Note F)	593,970		591,604	--		--		--			591,604

Dividends on redeemable convertible
preferred stock	--		--	--		--		(86,895	)		(86,895	)

Net loss for the year ended December 31, 1999	--		--	--		--		(3,227,976	)		(3,227,976	)

Balance - December 31, 1999	769,517	$	1,439,311	4,356,376	$	17,934,838	$	(5,228,484	)	$	14,145,665

See Notes to Consolidated Financial Statements.

F-6

Energy Search, Incorporated and Subsidiary

Consolidated Statement of Cash Flows

		Year Ended December 31,
		1999			1998
Cash Flows from Operating Activities
Net loss	$	(3,227,976	)	$	(394,428	)
Adjustments to reconcile net loss to net cash from (used in) operating activities:
Depreciation, depletion and amortization expense		2,511,266			1,551,685
Loss on impairment of long lived assets		688,663			--
Stock compensation expense		190,939			--
Dry holes and abandonments of previously capitalized oil and gas properties		--			43,033
Equity in income of related partnerships		(36,215	)		(107,356	)
Increase in deferred taxes		(222,300	)		(235,600	)
(Increase) decrease in assets:
Accounts receivable and due from partnerships		136,187			139,876
Other current assets		(28,821	)		1,444
Other assets		4,286			(29,760	)
Increase (decrease) in liabilities:
Accounts payable and accrued liabilities		472,188			(724,071	)

Net cash provided by operating activities		488,217			244,823

Cash Flows from Investing Activities
Purchase of proven properties		(5,738,412	)		(6,839,114	)
Purchase of wells and related equipment		(3,679,425	)		(3,256,434	)
Purchase of other property and equipment		(80,162	)		(30,951	)
Distributions from affiliated partnerships		45,602			77,006
Contributions to affiliated partnerships		--			(34,510	)
Purchase of oil and gas leases		(25,665	)		(15,651	)

Net cash used in investing activities		(9,478,062	)		(10,099,654	)

Cash Flows from Financing Activities
Gross proceeds from issuance of preferred stock		--			965,500
Payments on stock issuance costs - common stock		--			(64,155	)
Payments on stock issuance costs - preferred stock		(16,636	)		(117,793	)
Proceeds from issuance of long-term debt		19,039,344			7,599,093
Payment of dividends on preferred stock		(86,895	)		(17,601	)
Payment of loan issue costs		(422,899	)		--
Payments on long-term debt		(8,876,723	)		(166,780	)

Net cash provided by financing activities		9,636,191			8,198,264

Net Increase (Decrease) in Cash and Cash Equivalents		646,346			(1,656,567	)

Cash and Cash Equivalents - Beginning of year		595,749			2,252,316
Cash and Cash Equivalents - End of year	$	1,242,095		$	595,749

Supplemental Cash Flow Disclosures
Cash paid for interest	$	1,017,128		$	392,716
Cash paid for income taxes		--			100,370
Significant noncash activities:
Issuance of common stock for purchase of properties		537,037			1,822,944
Issuance of preferred stock for purchase of properties		608,240			--
Purchase of working interest - officers		225,000			--
Investments transferred to proved properties because of roll-ups		979,179			--

See Notes to Consolidated Financial Statements.

F-7

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note A - Summary of Significant Accounting Policies

Nature of Operations - Energy Search, Incorporated acquired Equity Financial Corporation, a wholly owned subsidiary, on May 1, 1997.

We are engaged in the exploration, development, production and marketing of oil and natural gas in the Appalachian Basin area including southeastern Ohio and southern West Virginia. Our revenue is primarily derived from:

	•	the sale of natural gas and crude oil from wells in which we have a working interest;

	•	the transmission of natural gas through a pipeline and gathering system;

	•	the management and operation of oil and gas wells; and

	•	to a lesser extent, the drilling of oil and gas wells on a contract basis.

In 1997, we transitioned from being primarily a driller-operator for syndicated affiliated drilling partnerships to an energy company developing reserves for our own account. Management is focused on the development of reserves and acquisition of primarily proved undeveloped properties for exploitation.

Equity Financial provides investment advice and brokers and deals in stocks, bonds and other securities in the east Tennessee region. Equity Financial uses a clearing broker on a fully disclosed basis to execute trades.

Principles of Consolidation - The consolidated financial statements include our accounts and those of Equity Financial. We have eliminated all significant inter-company balances and transactions in consolidation.

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

Oil and Gas Properties - We use the successful efforts method of accounting for oil and gas producing activities. Acquisition costs for proved and unproved properties are capitalized when incurred. Costs of unproved properties are transferred to proved properties when proved reserves are discovered. Exploration costs, including geological and geophysical costs and costs of carrying and retaining unproved properties, are charged to expense as incurred.

Exploratory drilling costs are capitalized initially; however, if it is determined that an exploratory well does not contain proved reserves, we charge these capitalized costs to expense, as dry hole costs, at that time.

F-8

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note A - Summary of Significant Accounting Policies (Continued)

In 1999 and 1998 we incurred certain indirect costs that management believes are related to the acquisition, exploration and development of oil and gas properties. We have capitalized some of these costs incurred in connection with properties we acquired for our own portfolio. We capitalized approximately $1,174,000 of indirect costs in 1999 and $1,353,000 in 1998. In addition, we capitalized to proven properties $123,000 of interest costs in 1999 and $166,000 in 1998.

We capitalize all intangible and tangible drilling costs for successful development wells drilled with our capital. Intangible drilling costs are the expense for labor, fuel, repair, hauling, rig rental and supplies used in the drilling of a well. Tangible costs are equipment such as casing, tubing, pumps, tanks and other equipment installed on a well. We generally expense costs incurred to operate and maintain wells and equipment and to lift oil and gas to the surface.

We periodically assess oil and gas properties that are individually significant for impairment of value, and we recognize a loss at time of impairment. Because the individual wells are generally insignificant and we primarily drill development wells, the impairment test is performed on a field basis. Proved properties represent purchased working interests in producing oil and gas wells, costs to acquire oil and gas leases and intangible well development costs. We depreciate and deplete oil and gas properties by the units-of-production method using estimates of proven reserves. Because of inherent uncertainties in estimating proven reserves, estimates of depletion and depreciation could change significantly.

Other Property and Equipment - We record other property and equipment at cost. We capitalize major additions and improvements, while we expense repairs, replacements and maintenance that do not improve or extend the life of the respective assets. We compute depreciation under accelerated methods over the estimated useful lives.

Investments in Related Partnerships - We account for investments in related partnerships by the equity method. As the managing general partner of the oil and gas partnerships, we make initial capital contributions to the partnerships in accordance with provisions in the respective placement memorandum governing the activities of the particular partnership. We allocate income or losses to the investments according to our ownership interest in the partnerships, and we deduct distributions or withdrawals from the investments (see Note B for additional partnership information).

Turnkey Drilling Revenue - We enter into contracts with the affiliated oil and gas partnerships to drill oil and gas wells under turnkey agreements. Under the terms of the contracts, we provide all tangible well equipment and receive working interests in the completed wells. The partnerships pay all intangible drilling costs and receive working interests in the wells. The partnerships advance funds to us to finance the drilling activity. We initially defer the full amount of the drilling advances and recognize drilling revenue as the wells are completed.

Income Taxes - We account for income taxes following the liability method. We recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns. We recognize deferred tax liabilities or assets for the estimated future tax effect of temporary differences between book and tax accounting and operating loss and tax credit carryforwards. We establish valuation allowances when necessary to reduce deferred tax assets to the amount expected to be realized.

F-9

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note A - Summary of Significant Accounting Policies (Continued)

Fair Value of Financial Instruments - A summary of the methods and significant assumptions used to estimate the fair value of financial instruments is as follows:

	•	Short-Term Financial Instruments - The fair value of short-term financial instruments, including cash, trade accounts receivable and trade accounts payable, approximate their carrying amounts in the financial statements due to the short maturity of such instruments.

	•	Notes Payable and Long-Term Debt - Based on interest rates currently available to us for debt instruments with similar terms and remaining maturities, the fair values of notes payable and long-term debt approximate their carrying amounts in the financial statements.

Stock Options and Warrants - We have stock option and stock warrant plans (Notes H and J). We use the intrinsic value method to account for options and warrants granted to employees, under which we record compensation expense at the amount by which the market price of the underlying stock at the grant date exceeds the exercise price of an option. When options and warrants are repriced or retired and reissued with a different exercise price, the intrinsic value method is applied on the new measurement date based on the current market price and the current exercise price to determine if compensation expense should be recorded. We use the fair value method to account for options and warrants granted to non-employees.

Basic Net (Loss) Per Common Share - Basic net (loss) per common share is based on net (loss) available to holders of common stock (net income less preferred stock dividends) divided by the weighted average number of shares of common stock outstanding during the period.

Diluted Net (Loss) Per Common Share - Diluted net (loss) per share of common stock is based on net (loss) before dividends divided by the weighted average number of shares of common stock outstanding plus dilutive potential shares of common stock outstanding during the period. Potential dilutive shares, consisting of stock options (Note J), warrants (Note H) and convertible preferred stock (Note F), were not included in the computation of diluted net (loss) per share of common stock in 1999 and 1998 because to do so would have been antidilutive.

Cash Equivalents - We consider all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

Reclassifications - We have made certain reclassifications to 1998 amounts to conform to 1999 presentations.

F-10

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note B - Affiliated Oil and Gas Partnerships

Since 1989, we have sponsored the formation of partnerships for the purpose of conducting oil and gas exploration, development and production activities on certain oil and gas properties. These partnerships included the Natural Gas/Tax Credit 1989 L.P., the Natural Gas/Tax Credit 1990 L.P., the Natural Gas/Tax Credit 1991 L.P., the Natural Gas/Tax Credit 1992 L.P., the Natural Gas/Tax Credit 1992-A L.P., the Energy Search Natural Gas 1993 L.P., the Energy Search Natural Gas 1993-A L.P., the Energy Search Natural Gas 1994 L.P., the Energy Search Natural Gas 1994-A L.P., the Energy Search Natural Gas 1995 L.P., the Energy Search Natural Gas 1995-A L.P., the Energy Search Natural Gas 1996 L.P. and the Energy Search Natural Gas 1996-A L.P., all of which have been or are in the process of being liquidated in 1999 and 1998 through our acquisition of the affiliated partnership working interests (Notes F and G).

We also have sponsored the following partnerships: the Energy Search Natural Gas 1997 L.P., the Energy Search Natural Gas 1997-A L.P. and the Energy Search Natural Gas 1998 L.P. We serve as managing general partner of these partnerships and have full and exclusive discretion in the management and control of the partnerships. The turnkey drilling and operating agreements that we enter into with the partnerships provide that the partnerships pay for the intangible drilling costs of the wells at an agreed-upon price per well. We provide all tangible equipment required in the drilling, equipping, completing and operating of the properties. Revenue from the partnership oil and gas properties is allocated based on the working interest ownership percentage of the properties. Our interests in the remaining limited partnerships were 1% at December 31, 1999 and ranged from 1% to 9% at December 31, 1998.

In 1993, we sponsored the formation of the ESI Pipeline Operating L.P., which purchased a portion of our gas pipeline and gathering system. We contributed our remaining interest in the pipeline system to the ESI Pipeline Operating partnership in exchange for an ownership interest in the partnership. We advanced funds to the ESI Pipeline Operating partnership for each extension of the pipeline. We provided a guaranteed 10% return to pipeline investors through 1997. Operations of the pipeline have been sufficient to fund the preferential return through 1997. After preferential returns, all cash is used to repay advances used to fund pipeline extensions.

Also, in 1993, we sponsored the formation of the ESI Natural Gas Pipeline Income L.P. This partnership made a capital contribution to the ESI Pipeline Operating partnership to finance the initial purchase of the pipeline system. In turn, the ESI Natural Gas Pipeline Income partnership received an ownership interest in the ESI Pipeline Operating partnership. We serve as managing general partner for both of these partnerships and, as such, have full and exclusive discretion in the management of and control of the partnerships. The ESI Pipeline Operating partnership earns revenue by charging gas wells a transportation fee based on the volume of gas moved through the pipeline system. We operate substantially all of these gas wells.

During 1999, the ESI Pipeline Operating partnership and the ESI Natural Gas Pipeline Income partnership were liquidated through our acquisition of the affiliated partnership interests (Note F).

Total assets and equity of the related partnerships in the aggregate were approximately $121,129 and $121,129, respectively, at December 31, 1999, and $4,779,900 and $4,737,051, respectively, at December 31, 1998.

F-11

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note B - Affiliated Oil and Gas Partnerships (Continued)

Our share of revenue and net income for our equity investees for the years ended December 31, 1999 and 1998 are listed below. In the case of each equity investee, the net income (loss) from continuing operations equals the net income (loss).

Equity Investee		Revenue				Net Income (Loss) From Continuing Operations
		1999		1998		1999		1998

Energy Search Natural Gas Pipeline Income, L.P. *	$	3,064	$	4,673	$	3,064	$	4,673

ESI Pipeline Operating L.P.*		49,457		86,059		24,795		78,978

Energy Search Natural Gas 1993 L.P.*		1,110		2,604		1,110		2,596

Energy Search Natural Gas 1993-A L.P.*		2,300		5,338		2,300		5,338

Energy Search Natural Gas 1994 L.P.*		1,301		5,695		1,301		5,677

Energy Search Natural Gas 1994-A L.P.*		133		502		133		502

Energy Search Natural Gas 1995 L.P.*		1,165		3,741		1,165		3,741

Energy Search Natural Gas 1995-A L.P.*		903		3,272		903		3,272

Energy Search Natural Gas 1996 L.P.*		606		1,247		606		1,247

Energy Search Natural Gas 1996-A L.P.*		182		360		182		360

Energy Search Natural Gas 1997 L.P.		369		668		369		668

Energy Search Natural Gas 1997-A L.P.		201		318		201		304

Energy Search Natural Gas 1998 L.P.		86		--		86		--

* Represents amounts earned before affiliated partnership roll-ups.

F-12

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note C - Property and Equipment

The principal categories of property and equipment are as follows:

		1999		1998	Depreciable Life-Years

Machinery and equipment	$	41,005	$	41,005	5
Office furniture, equipment and software		318,177		311,657	5
Airplane		181,838		165,932	5
Vehicles		264,739		218,645	5

Total cost		805,759		737,239

Less accumulated depreciation		518,724		449,493

Net carrying amount	$	287,035	$	287,746

Depreciation expense totaled $81,086 for the year ended December 31, 1999 and $106,385 for the year ended December 31, 1998.

Note D - Income Taxes

We file a consolidated federal income tax return with Equity Financial. The following is a summary of the provisions for income taxes:

		Year Ended December 31,
		1999		1998

Current tax benefit	$	2,300	$	--
Deferred tax benefit		1,322,900		235,600
Change in valuation allowance		(1,100,600	)	--
Total income tax benefit	$	224,600	$	235,600

The following is a reconciliation of the statutory federal income tax rate to our effective tax rate:

	1999		1998

Income tax at federal statutory rate	34.0%		34.0%
State income tax, net of federal benefit	6.0%		6.0 %
Change in valuation allowance for deferred tax assets	(32.5%	)	--
Other	(1.0%	)	(2.6%	)

Actual effective tax rate	6.5 %		37.4%

F-13

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note D - Income Taxes (Continued)

The significant components of our deferred tax assets and liabilities are as follows:

		1999		1998
Deferred tax assets:
Accounting for equity investments	$	3,900	$	128,900
Pipeline and equipment		125,200		--
Federal net operating loss		3,595,500		1,771,100
State net operating loss		192,500		99,600
Impairment charges		234,100		--
Geological and engineering costs		100,000		106,900
Other		1,600		--

Total deferred tax asset		4,252,800		2,106,500

Valuation allowance for deferred tax assets		(1,100,600	)	--

Deferred tax liabilities:
Depreciation and pooling of capital		1,083,600		832,900
Intangible drilling costs		958,200		349,200
Other		2,100		38,400

Total deferred tax liabilities		2,043,900		1,220,500

Net deferred tax asset	$	1,108,300	$	886,000

At December 31, 1999, we had federal operating loss carryforwards of approximately $10,575,000 and state operating loss carryforwards of $6,868,000. These carryforwards expire in the years 2005 to 2019 and are available to offset future taxable income.

F-14

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note E - Long-Term Debt

Long-term debt consisted of the following:

		December 31,
		1999		1998
Line of credit at bank, available balance of $30,000,000 at December 31, 1999. Collateralized by lien on oil and gas property, interest payable monthly at 11%. Principal payments begin July 31, 2000, payable in monthly installments based on a percentage of the outstanding balance. This percentage ranges from .32% to 2.22% through March 2007	$	18,019,344	$	--

Line of credit at bank, available balance of $7,800,000 at December 31, 1998. Collateralized by lien on oil and gas property, interest payable at prime plus 1.25% at December 31, 1998 (a 9.0% effective rate). This note was refinanced during 1999		--		7,749,776

Note payable to bank, collateralized by equipment, payable in monthly installments of $8,400, including interest at 7.75%, with any unpaid principal balance due December 5, 2003		438,053		500,000

Note payable to officers, interest payable at 10% with any unpaid principal balance due December 31, 2001		180,000		--

Total		18,637,397		8,249,776

Less current portion		2,337,373		546,407

Total long-term debt	$	16,300,024	$	7,703,369

We are subject to various loan covenants in connection with bank notes payable described above, including requirements on our working capital, capital expenditures, debt coverage ratio, restrictions on payment of dividends and restrictions on certain cash balances. We segregate cash received from oil and gas sales into a separate cash account with our bank. We must submit requests for reimbursement from the bank for certain operating expenses and principal and interest payments. In addition, the purpose for additional draws on the line of credit in place at December 31, 1999 must be approved by the bank.

The bank line of credit entitles the bank to receive a 3% overriding royalty interest on all of our oil and gas production. In addition, the agreement provides the bank with the first option to purchase and market all natural gas produced from our wells, provided it can do so on purchase terms no less favorable than we could obtain marketing our own natural gas.

F-15

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note E - Long-Term Debt (Continued)

Principal maturities of long-term debt at December 31, 1999 are as follows:

2000	$	2,337,373
2001		4,087,151
2002		2,902,329
2003		2,787,541
2004		2,158,717
2005 and thereafter		4,364,286

Total	$	18,637,397

Note F - Preferred Stock

Redeemable Convertible Preferred Stock - In 1998, we initiated a private placement offering of up to 800,000 shares of 9% redeemable convertible preferred stock. We terminated the offering on December 18, 1998, and adjusted the issue price of the preferred stock to $5.50 per share according to the terms of the offering. We raised $847,707, net of issue costs of $117,793, and sold 175,547 shares of preferred stock under the offering.

The shares of preferred stock have a liquidation and dividend preference over our common stock and are convertible to common stock at the option of the holder at any time at a rate of one share of common stock for each share of preferred stock. Conversion of the preferred stock to common stock will automatically occur if we are acquired or are the subject of a business combination in which substantially all of our assets are acquired by unaffiliated purchasers or greater than 50% of the outstanding beneficial interest of our common stock is acquired by unaffiliated purchasers.

The shares of preferred stock are redeemable at our sole option any time after September 30, 1999, provided the average trading closing price for our common stock exceeds 130% of the issue price of the preferred stock over any five consecutive trading day period beginning after September 30, 1999. The redemption price for the preferred stock will be 100% of the issue price for the preferred stock, plus accrued but unpaid dividends. We will provide the holders of preferred stock 30 days written notice of our intent to redeem the preferred stock during which time the holders may, at their option, convert their preferred stock to common stock.

Affiliated Partnership Roll-Up - Effective December 31, 1999, we closed the acquisition of working interests in a total of 13 gross natural gas and oil wells and a pipeline that we operated. These interests were owned by the following affiliated partnerships: the Natural Gas Pipeline Income L.P., the Natural Gas/Tax Credit 1996 L.P. and the Natural Gas/Tax Credit 1996-A L.P.

F-16

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note F - Preferred Stock (Continued)

We issued an aggregate of 428,520 shares of 9% redeemable convertible preferred stock, $4.00 par value, to acquire the pipeline. The preferred stock was recorded at $423,240 based on the fair value of the pipeline acquired. In recording this acquisition we concluded that our receivable from an investment in the pipeline was impaired and we recorded an impairment loss of approximately $640,000.

We issued an aggregate of 165,450 shares of 9% redeemable convertible preferred stock to acquire the interests of the Natural Gas/Tax Credit 1996 L.P. and the Natural Gas/Tax Credit 1996-A L.P. The preferred stock was recorded at $185,000 based on the fair value of the working interests in the wells acquired. In recording this acquisition, we concluded that our receivable from an investment in the partnerships was impaired and we recorded an impairment loss of approximately $50,000.

Note G - Common Stock

Stock Issued to Employees and Non-Employees - During 1999, we issued 86,469 shares of common stock to employees for past services rendered. In addition, we issued 7,119 shares of common stock to non-employees for past services rendered. We charged $190,939 to operations during 1999 for the issuance of this stock.

Affiliated Partnership Roll-Ups - Effective January 1, 1999, we closed the acquisition of working interests in a total of 93 gross natural gas or oil wells that we operated. These interests were owned by the following affiliated partnerships: 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. We paid aggregate purchase consideration of $708,948, which included $504,815 in our common stock (229,955 shares) and $204,133 in cash.

The acquisition of these interests from affiliated partnerships followed a group of similar transactions pursuant to which we acquired minor working interests and overriding royalty interests in the wells from three individuals. These minor interest acquisitions had an effective date of October 1, 1999. We paid aggregate purchase consideration of $32,222 in our common stock (15,525 shares).

Effective June 30, 1998, we closed the acquisition of working interests in a total of 145 gross natural gas or oil wells that we operated. These interests were owned by the following affiliated partnerships: the Natural Gas/Tax Credit 1989 L.P., the Natural Gas/Tax Credit 1990 L.P., the Natural Gas/Tax Credit 1991 L.P., the Natural Gas/Tax Credit 1992 L.P. and the Natural Gas/Tax Credit 1992-A L.P. We paid aggregate purchase consideration of $2,223,941, which included $1,716,748 in our common stock (221,453 shares) and $507,193 in cash.

F-17

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note G - Common Stock (Continued)

The 1998 acquisition of the interests from affiliated partnerships followed a group of smaller transactions pursuant to which we acquired minor working interests and overriding royalty interests in the wells from nine individuals. These minor interest acquisitions had an effective date of April 16, 1998. We paid aggregate purchase consideration amounting to $227,740, which included $106,197 in our common stock (10,114 shares) and $121,543 in cash.

Note H - Stock Warrant Plans

Regulation D Warrants - As part of our private offering of common stock in October 1997, we issued 74,996 warrants to unaffiliated parties under a placement agent agreement. The warrants entitle each holder to purchase one share of common stock and are exercisable at $7.00 per share at any time until October 27, 2002. During 1999, 13,925 of these warrants were repriced at $4.50 per share. The number, type of security and the exercise price is subject to adjustment upon occurrence of certain events including consolidation, merger, subdivision or combination of shares and issuance of stock dividends. None of these warrants have been exercised at December 31, 1999.

Series W-1 Warrants - We issued 100,000 warrants to Southern Producer Services, L.P. pursuant to a new financing agreement in 1999. Each warrant entitles Southern Producer to purchase one share of common stock, exercisable at $6.50 per share at any time until June 23, 2004. The number, type of security and the exercise price is subject to adjustment upon occurrence of certain events including consolidation, merger, subdivision or combination of shares and issuance of stock dividends. None of these warrants have been exercised at December 31, 1999.

The following is a summary of stock warrant activity with unaffiliated parties:

	Number of Warrants			Exercise Price	Expiration Date

Outstanding - January 1, 1998
and December 31, 1998	1,274,996		$	9.60-7.00	January 30, 2002-
					October 27, 2002

Retired	(13,925	)	$	7.00	October 27, 2002

Reissued	13,925		$	4.50	October 27, 2002

Granted	100,000		$	6.50	June 23,2004

Outstanding - December 31, 1999	1,374,996

F-18

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note I - Related-Party Transactions

Due to the nature of our business, a significant number of transactions are with related parties.

We received $0 in 1999 and $115,200 in 1998 from affiliated oil and gas partnerships for drilling costs which were the responsibility of the affiliated partnerships. Included in accounts receivable is $3,889 at December 31, 1999 and $59,002 at December 31, 1998 due from affiliated partnerships.

In our role as operator of the oil and gas wells owned by various related partnerships, we charge a monthly wellhead and administrative fee of between $100 and $300 for each producing well. These fees totaled $46,100 in 1999 and $110,856 in 1998. In our role as general partner of the ESI Pipeline Operating partnership (Note B), we charged the partnership a management fee of $2,500 per month for 1999 and 1998. These fees totaled $25,000 in 1999 and $35,000 in 1998. The 1998 reflects amounts collected in 1998 for expenses incurred in 1997. The monthly management fee was terminated December 31, 1999 in conjunction with the roll-up of the ESI Pipeline Operating partnership (Note B).

During 1999, we issued a note totaling $225,000 to three officers for their interests in various properties and their rights to invest in future properties.

In our discretion and given the business environment existing at the time, we chose not to collect certain amounts due from partnerships and also paid certain expenses due to others on behalf of partnerships. We are under no legal or contractual obligation to continue this activity, and there is no expectation that it will continue in future years.

The following is a summary of expenses paid on behalf of the partnerships and advances forgiven:

		Year Ended December 31,
		1999		1998

Expenses paid on behalf of partnership	$	104,303	$	192,837

Advances forgiven	$	18,452	$	820

We have the contractual right to charge partnership administrative fees and production operating fees in excess of the aggregate amounts charged to the partnerships during 1999 and 1998.

Note J - Employee Benefit and Stock-Based Compensation Plans

Employee Benefit Plan - We sponsor a simplified employee pension plan for qualifying employees. Employee contributions to individual retirement plans may not exceed the greater of 15% of employee earnings or $22,500 per year per employee. We contributed $36,197 to the pension plan in 1999 and $38,792 in 1998.

Non-employee Options - We issued 6,695 options to non-affiliated parties during 1999 for services rendered. Each option issued entitles the holder to purchase one share of common stock at an exercise price of $4.50 to $6.50 per share. The options expire July 20, 2004.

F-19

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note J - Employee Benefit and Stock-Based Compensation Plans (Continued)

We issued 2,500 options to non-affiliated parties in 1998 for services rendered. The options issued in 1998 entitle the holder to purchase one share of common stock at an exercise price of $6.50 and expire July 30, 2002.

We issued 2,500 options each to the two outside directors during 1998. Options issued in 1998 were repriced in 1999 and entitle the holder to purchase one share of common stock at an exercise price of $4.50. The options expire January 30, 2004.

During 1998, we charged $6,700 to expense related to these non-employee options.

Employee Option Plan - We have a fixed employee stock-based compensation plan under which we granted options for 47,958 shares of restricted common stock in 1999, at exercise prices ranging from $4.25 to $4.50 per share. The options expire in five years and vest immediately upon grant.

In addition, we granted options for 22,500 shares of restricted common stock under the fixed employee stock-based compensation plan in 1998. The exercise price of each option was $8.00 when granted, but those options were repriced to $4.50 per share in 1998. The terms of these options is five years starting in 1998. The options vest at 4,500 shares per year.

Officer Warrant Plan - We had a fixed executive officer stock-based compensation plan under which executive officers have been granted warrants to purchase up to 450,000 shares of restricted common stock. During 1999, we replaced the outstanding warrants with options, issued under our fixed employee stock-based compensation plan. The exercise price of each option is $4.50 per share, repriced from $8.00 per share. The term of the options is five years starting in 1997 and the options vest at 30,000 shares per officer per year.

We apply intrinsic value accounting to our fixed stock-based compensation plans. Accordingly, we have not recognized compensation cost for the fixed plans in 1999 and 1998. Had compensation cost been determined using the fair value method, net loss would have been $(3,776,353) in 1999 and $(551,517) in 1998, and basic and fully diluted loss per share would have been $(.92) in 1999 and $(0.15) in 1998. The fair value of the warrants and options was determined using the Black-Scholes model with application of an additional 30% discount due to the fact that the shares are restricted. Assumptions made in estimating the fair value include: risk-free interest rate of 6%, expected expiration of the warrants of January 30, 2004, expected price volatility of 20% and dividend yield of 0%.

F-20

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note J - Employee Benefit and Stock-Based Compensation Plans (Continued)

The following is a summary of the status of the fixed stock-based compensation plans during 1999:

		Number of Shares		Weighted Average Exercise Price

Outstanding - January 1, 1998		513,150	$	7.84

Granted		2,500		6.50
Granted		5,000		5.25
Granted		22,500		8.00

Outstanding - December 31, 1998		543,150		7.53

Retired		(538,150	)	7.53
Reissued		538,150		4.50
Granted		1,195		6.50
Granted		5,500		4.50
Granted		2,958		4.50
Granted		45,000		4.25

Outstanding - December 31, 1999		597,803	$	4.50

Exercisable at December 31, 1999		404,303	$	4.50

Weighted average per share fair value of options granted during 1999	$	0.93

The following is a summary of the status of the fixed options outstanding at December 31, 1999:

Outstanding Options			Exercisable Options
Exercise Price	Number	Weighted Average Remaining Contractual Life	Exercise Price	Number	Weighted Average Remaining Contractual Life

$4.25	45,000	4	$4.25	45,000	4

$4.50	536,608	3	$4.50	343,108	3

$5.25	5,000	2	$5.25	5,000	2

$6.50	11,195	3	$6.50	11,195	3

F-21

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note K - Commitments, Contingencies and Concentrations

As general partner in various affiliated oil and gas partnerships, we are subject to contingencies that may arise in the normal course of business of these partnerships. Management is of the opinion that liabilities, if any, related to these contingencies would not be material to our financial statements.

Concentrations of Credit Risk - We extend credit to affiliated partnerships in the normal course of business. Within this industry, certain concentrations of credit risk exist. In our role as operator of co-owned properties, we assume responsibility for payment to vendors for goods and services related to joint operations and extend credit to these partnerships as co-owners of these properties.

This concentration of credit risk may be similarly affected by changes in economic or other conditions and may, accordingly, impact our overall credit risk. However, management believes that our accounts receivable are well diversified, thereby reducing potential risk to us.

Geographic Concentration - We plan to increase our oil and gas reserves by continued developmental drilling in southeastern Ohio in the area serviced by the gas gathering system, the Dupont field in Wood County, West Virginia and the Beaver Coal Company Lease in Raleigh County, West Virginia. We also may undertake activities elsewhere in the Appalachian Basin and the mid-continent region of the United States. We plan to drill an increasing number of wells for our own account.

Note L - Business Segments

We adopted SFAS No. 131, Disclosures About Segments of an Enterprise and Related Information, in 1997 which changes the way we report information about our operating segments. We have restated the information for 1998 to conform to the 1999 presentation.

Our operations are classified into two principal industry segments: oil and gas operations and brokerage services. We conduct all of our oil and gas operations which is our primary industry segment. The brokerage services are conducted exclusively through Equity Financial. See Note A for a description of the operations and accounting policies of each company. The following is a summary of segment information for 1999 and 1998:

F-22

Energy Search, Incorporated and Subsidiary

Notes to Consolidated Financial Statements
December 31, 1999 and 1998

Note L - Business Segments (Continued)

		Oil & Gas Operations		Brokerage Services		Totals

1999
Revenue	$	3,451,596	$	457,202	$	3,908,798
Segment profit (loss)		(3,197,739	)	(30,237	)	(3,227,976	)
Intersegment revenue		--		--		--
Total assets		33,785,720		102,207		33,887,927
Capital expenditures		9,497,999		--		9,497,999
Equity method income		36,215		--		36,215
Interest expense		1,059,231		--		1,059,231
Depreciation, depletion and amortization		2,505,761		5,505		2,511,266

1998
Revenue	$	2,956,832	$	463,666	$	3,420,498
Segment profit (loss)		(387,043	)	(7,385	)	(394,428	)
Intersegment revenue		--		9,600		9,600
Total assets		24,888,353		135,056		25,023,409
Capital expenditures		10,142,150		--		10,142,150
Equity method income		107,356		--		107,356
Interest expense		392,716		--		392,716
Depreciation, depletion and amortization		1,545,631		6,054		1,551,685

Note M - Subsequent Events

Subsequent to year end, we purchased approximately 6,500 acres of oil and gas properties, which included 45 producing wells and related equipment for $1,600,000.

F-23

Supplementary Information

F-24

To the Shareholders of
Energy Search, Incorporated and Subsidiary

We have audited the financial statements of Energy Search, Incorporated and Subsidiary for the years ended December 31, 1999 and 1998. The accompanying schedules of Costs Incurred in Oil and Gas Producing Activities and Estimates of Natural Gas and Oil Reserves on pages 26 through 28 are not a required part of the basic financial statements of Energy Search, Incorporated, but constitute additional supplementary information required by the Financial Accounting Standards Board. We have applied certain limited procedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the supplementary information. However, we did not audit the information and express no opinion on it.

Grand Rapids, Michigan
March 17, 2000

F-25

Energy Search, Incorporated and Subsidiary

Supplementary Information (Unaudited)

Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following costs are comprised of both capitalized and expensed costs included in the balance sheet and income statement:

		Year Ended December 31
		1999		1998

Property acquisition costs	$	3,221,780	$	4,560,556

Exploration costs	$	76,815	$	218,369

Developments costs	$	6,810,971	$	6,607,991

Estimates of Natural Gas and Oil Reserves

The following estimates of proven developed natural gas and oil reserve quantities and related standardized measure of discounted net cash flow are estimates prepared by an independent petroleum engineer on behalf of our engineer as of December 31, 1999 and 1998. They do not purport to reflect realizable values or fair market values of our reserves. We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Proven reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proven developed reserves are those expected to be recovered through existing wells, equipment and operating methods.

The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas to the estimated future production of proven oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proven reserves, less estimated future severance tax expenses and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows.

F-26

Energy Search, Incorporated and Subsidiary

Supplementary Information (Unaudited)

Estimates of Natural Gas and Oil Reserves (Continued)

	Oil (BBL)		Gas (MCF)

Proven, developed and undeveloped reserves:

January 1, 1998	23,624		30,609,977
Revisions and other changes	3,576		(3,450,274	)
Extensions and discoveries	--		11,606,732
Purchases and sales of reserves	24,585		5,788,007
Production	(7,231	)	(1,061,388	)

December 31, 1998	44,554		43,493,054
Revisions and other changes	9,652		611,840
Extensions and discoveries	74,854		8,871,816
Purchases and sales of reserves	372,611		9,259,534
Production	(20,432	)	(1,488,334	)
December 31, 1999	481,239		60,747,910


Proven developed reserves (1):
December 31, 1998	44,554		15,990,954
December 31, 1999	224,171		25,720,380

Equity interest in proven reserves (2):
December 31, 1998	103		124,326
December 31, 1999	--		2,690

_____________________

(1)	We own these reserves directly.

(2)	These are reserves owned indirectly by us through our interests in affiliated partnership.

F-27

Energy Search, Incorporated and Subsidiary

Supplementary Information (Unaudited)

Estimates of Natural Gas and Oil Reserves (Continued)

		December 31,
		1999		1998
Standardized measure of discounted future pretax net cash flows

Future cash inflows	$	204,937,700	$	121,902,800
Future production costs		(31,731,964	)	(23,279,515	)
Future development costs		(28,104,260	)	(21,171,030	)

Future pretax net cash flows		145,101,476		77,452,255
10% annual discount for estimated timing of cash flows		(85,373,926	)	(46,690,672	)

Standardized measure of discounted future pretax net cash flows
relating to proven oil and gas reserves	$	59,727,550	$	30,761,583

Standardized measure of discounted future net cash flows

Future cash inflows	$	204,937,700	$	121,902,800
Future production costs		(31,731,964	)	(23,279,515	)
Future development costs		(28,104,260	)	(21,171,030	)
Future income taxes		(39,555,212	)	(23,610,860	)
Future net cash flows		105,546,264		53,841,395
10% annual discount for estimated timing of cash flows		(54,810,060	)	(29,975,411	)

Standardized measure of discounted future net cash flows relating to
proven oil and gas reserves	$	50,736,204	$	23,865,984

Our share of equity method investors' standardized measure of
discounted future cash flows	$	3,269	$	124,376

The following reconciles the change in the standardized measure of discounted future net cash flows:

		1999		1998
Beginning of year	$	23,865,984	$	24,095,367
Sales of oil and gas produced, net of production costs		(3,318,496	)	(2,444,574	)
Extensions, discoveries, and improved recovery -
Less related costs		16,775,903		9,806,445
Revisions of previous quantity estimates		688,320		(2,632,622	)
Changes in prices		10,311,450		(12,778,261	)
Net change from purchases and sales of minerals in place		15,536,903		6,498,274
Net change in income taxes		(15,944,352	)	(1,461,434	)
Accretion of discount		(2,386,598	)	(2,409,537	)
Other		5,207,090		5,192,326
End of year	$	50,736,204	$	23,865,984

F-28

EXHIBIT INDEX

Exhibit
Number Description

3.1 Fourth Amended and Restated Charter of the Registrant(1)

3.2 Articles of Amendment to Charter (2)

3.3 Bylaws of the Registrant(3)

4.1 Specimen of Common Stock Certificate(4)

4.2 Specimen of Redeemable Series A Common Stock Purchase Warrant Certificate(4)

4.3 Specimen of Underwriters' Warrant Certificate(4)

4.4 Charter (See Exhibits 3.1 and 3.2)

4.5 Bylaws (See Exhibit 3.3)

9.1 Shareholder Voting Agreement and Irrevocable Proxy(4)

10.1 Energy Search Natural Gas 1995-A L.P. Limited Partnership Agreement, dated March 31, 1995(4)

10.2 Energy Search Natural Gas 1995-A L.P. Joint Drilling and Operating Agreement, dated March 31, 1995(4)

10.3 Energy Search Natural Gas 1996 L.P.-Limited Partnership Agreement, dated September 10, 1996(4)

10.4 Energy Search Natural Gas 1996 L.P.-Joint Drilling and Operating Agreement, dated September 10, 1996(4)

10.5 ESI Pipeline Operating Partnership-Limited Partnership Agreement, dated January 7, 1993(4)

10.6 Energy Search Natural Gas Pipeline Income Partnership-Limited Partnership Agreement, dated January 7, 1993(4)

10.7 Gas Servicing Agreement between the Registrant and ESI Pipeline Operating L.P., dated January 5, 1993(4)

10.8 Selling Agreement-Class B Convertible Preferred Shares between Registrant and Equity Financial Corporation, dated March 4, 1996(4)

10.9 Selling Agreement-Class A and Class B Preferred Shares between Registrant and Equity Financial Corporation, dated March 4, 1996(4)

10.10 Selling Agreement-Variable Rate Subordinated Debentures between Registrant and Equity Financial Corporation, dated September 19, 1994(4)

10.11 Aircraft Lease between Charles P. Torrey, Jr. and the Registrant dated February 1, 1995(4)

10.12 Beaver Coal Company Lease between Beaver Coal Company Limited and the Registrant, dated September 15, 1996(4)

10.13 Amended and Restated Employment Agreements with officers and key employees of the Registrant:
         (a)         John M. Johnston(5)*
         (b)         Robert L. Remine(5)*
         (c)         Charles P. Torrey, Jr.(5)*
         (d)         Richard S. Cooper(5)*

10.14 Promissory Notes of Executive Officers in Favor of Registrant:
         (a)         Charles P. Torrey, Jr.(4)
         (b)         Robert L. Remine(4)
         (c)         Richard S. Cooper(4)

10.15 Stock Option Plan(4)*

10.16 Outside Directors' Stock Option Plan(4)*

10.17 Form of Lock-Up Agreement(4)

10.18	Stock Option and Restricted Stock Plan of 1998, as amended(6)*
10.19	Form of Indemnification Agreement (1)*
10.20	1998 Stock Option and Restricted Stock Plan for Outside Advisors and Consultants(7)
10.21	Credit Agreement between the Registrant and Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.22	First Amendment to Credit Agreement between the Registrant and Southern Producer Services, L.P., dated as of October 21, 1999(5)
10.23	Form of Note in the amount of $30,000,000 payable to Southern Producer Services, L.P., dated June 23, 1999(5)
10.24	Mortgage, Deed of Trust, Assignment, Security Agreement and Financing Statement from the Registrant to Brian P. Shannon, David W. Stewart and Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.25	Credit Line Deed of Trust, Assignment of Production, Security Agreement and Financing Statement from the Registrant to William C. Martin, trustee, and Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.26	Pledge Agreement made by the Registrant in favor of Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.27	Warrant to Purchase Common Stock of the Registrant, expiring June 23, 2004(5)
10.28	Assignment and Conveyance of Overriding Royalty Interest between the Registrant and Southern Producer Services, L.P., dated as of June 23, 1999(5)
10.29	Base Contract for Short-Term Sale and Purchase of Natural Gas between the Registrant and Southern Producer Services, L.P.(5)
11.1	Statement Regarding Computation of Earnings Per Common Share
21.1	Subsidiaries(8)
23.1	Consent of Experts and Counsel (a) Consent of Independent Accountant, Plante & Moran, LLP, CPA (b) Consent of Independent Petroleum Consultant, Wright & Company, Inc.
27.1	Financial Data Schedule

	[X]	ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the fiscal year ended December 31, 1999

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

	For the transition period from ____________________ to _____________________

Tennessee (State or Other Jurisdiction of Incorporation or Organization)	62-1423071 (I.R.S. Employer Identification No.)
280 Fort Sanders West Blvd., Suite 200 Knoxville, Tennessee (Address of Principal Executive Offices)	37922 (Zip Code)
(800) 551-5810 (Issuer's Telephone Number, Including Area Code)

	•	significant reserve potential
	•	a well developed company infrastructure of gathering systems and pipelines
	•	premium pricing and economics

	•	steam
	•	process heat and co-generation for industrial uses
	•	feedstock for chemicals used in fertilizer and gasoline production
	•	electric generation
	•	residential and commercial heating

	•	seasonality
	•	the condition of the United States economy
	•	foreign imports of oil and natural gas
	•	political conditions in other oil and natural gas producing countries
	•	the actions of the Organization of Petroleum Exporting Countries
	•	domestic government regulation, legislation and regulatory policies

	•	require the acquisition of a permit or other authorization before construction or drilling commences
	•	restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities
	•	limit or prohibit construction, drilling and other activities on certain lands lying within wilderness, wetlands and other protected areas
	•	require remedial measures to mitigate pollution from former operations such as plugging abandoned wells
	•	impose substantial liabilities for pollution resulting from our operations

	•	fires
	•	natural disasters
	•	explosions
	•	encountering formations with abnormal pressures
	•	blowouts
	•	craterings
	•	pipeline ruptures and spills
	•	uncontrollable flows of oil, natural gas or well fluids

	at December 31,
	1999	1998	1997

Company - Total
Total Proved Reserves:⁽¹⁾
Oil (Bbls)	481,238	44,554	23,624
Natural Gas (Mcf)	60,747,920	43,493,054	30,609,977
Equivalent Bbls (BOE)⁽²⁾	10,605,891	7,293,396	5,125,287
Equivalent Mcf (Mcfe)⁽²⁾	63,635,348	43,760,378	30,751,721
Total Proved Undeveloped Reserves:⁽¹⁾
Oil (Bbls)	257,067	--	--
Natural Gas (Mcf)⁽²⁾	35,027,540	27,502,100	19,417,960
Equivalent Bbls (BOE)⁽²⁾	6,094,990	4,583,683	3,236,327
Equivalent Mcf (Mcfe)⁽²⁾	36,569,942	27,502,100	19,417,960
Total Proved Developed Reserves:⁽¹⁾
Oil (Bbls)	224,171	44,554	23,624
Natural Gas (Mcf)	25,720,380	15,990,954	11,192,017
Equivalent Bbls (BOE)⁽²⁾	4,510,901	2,709,713	1,888,960
Equivalent Mcf (Mcfe)⁽²⁾	27,065,406	16,258,278	11,333,761

(1)	Reserves are net to our interest. Applicable royalties have been deducted from these volumes.
(2)	After conversion on the basis of 6.0 Mcf of natural gas to 1.0 barrel of crude oil.

	Oil		Natural Gas		Total
Region	Gross	Net	Gross(1)	Net	Gross	Net

Ohio	45	45	464	453	509	498
West Virginia	1	1	54	54	55	55
Total	46	46	518	507	564	553

	Developed		Undeveloped		Total
Region	Gross	Net	Gross	Net	Gross	Net

Ohio	48,005	47,441	31,194	31,194	79,199	78,635
West Virginia	20,039	19,635	90,881	85,421	110,920	105,056
Total	68,044	67,076	122,075	116,615	190,119	183,691

•	the impact that the following factors can have on our business and the energy resource industry in general:

	•	lack of product diversity: our reliance on natural gas could place us at a disadvantage with respect to our competitors that are more diversified; this situation could arise if, for example, natural gas prices fell while other energy commodity prices rose

	•	lack of geographical diversity: due to our concentration in the Appalachian Basin, we are susceptible to regional factors that may place us at a disadvantage relative to our competitors; these regional factors include: regional disasters, such as tornadoes, floods and wind storms; or particularly harmful changes in state or local laws

	•	changes in competition and pricing environments: if competition increases in segments of the energy resource industry, larger companies with greater capital reserves and greater diversification may have more options at their disposal for handling increased competition than we do

	•	potential negative side effects stemming from our shift away from our joint ventures with affiliated drilling partnerships: as a result of this shift, our capitalization strategies have evolved, and our current strategy necessarily involves pitfalls that we, being relatively new to this type of capitalization, may fail to recognize due to lack of experience

	•	the timing and extent of our success in discovering, acquiring, developing and producing natural gas and oil resources

	•	risks incident to the drilling and operation of natural gas and oil wells

	•	changes in future production development costs

Exhibit Number	Description

3.1	Fourth Amended and Restated Charter of the Registrant(1)
3.2	Articles of Amendment to Charter (2)
3.3	Bylaws of the Registrant(3)
4.1	Specimen of Common Stock Certificate(4)
4.2	Specimen of Redeemable Series A Common Stock Purchase Warrant Certificate(4)
4.3	Specimen of Underwriters' Warrant Certificate(4)
4.4	Charter (See Exhibits 3.1 and 3.2)
4.5	Bylaws (See Exhibit 3.3)

(1)	Previously filed with our Definitive Proxy Statement filed on April 28, 1998 with the Securities and Exchange Commission, and here incorporated by reference.

(2)	Previously filed with our Form 10-QSB for the quarter ended June 30, 1999, and here incorporated by reference.

(3)	Previously filed with our Form 10-QSB for the quarter ended June 30, 1998, and here incorporated by reference.

(4)	Previously filed with our Registration Statement on Form SB-2 (Registration No. 333-12755) filed with the Securities and Exchange Commission, and here incorporated by reference.

(5)	Previously filed with our Form 10-QSB for the quarter ended September 30, 1999, and here incorporated by reference.

(6)	Previously filed with our Definitive Proxy Statement filed on April 30, 1999 with the Securities and Exchange Commission, and here incorporated by reference.

(7)	Previously filed with our Form 10-QSB Quarterly Report for the quarter ended September 30, 1998, and here incorporated by reference.

(8)	Previously filed with our Form 10-KSB Annual Report for the fiscal year ended December 31, 1997, and here incorporated by reference.

	Item 13(b). Reports on Form 8-K

Signature	Title	Date


/s/ Charles P. Torrey, Jr. Charles P. Torrey, Jr.	Chief Executive Officer and Director (Principal Executive Officer)	March 30, 2000


/s/ Richard S. Cooper Richard S. Cooper	President and Director	March 30, 2000


/s/ Robert L. Remine Robert L. Remine	Secretary, Treasurer and Director (Principal Financial and Accounting Officer)	March 30, 2000